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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
---------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 1-12079
Calpine Corporation
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date:
416,047,134 shares of Common Stock, par value $.001 per share, outstanding on
May 7, 2004
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CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2004
INDEX
Page No.
--------
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Balance Sheets March 31, 2004 and December 31, 2003........................... 3
Consolidated Condensed Statements of Operations for the Three Months Ended
March 31, 2004 and 2003............................................................................ 5
Consolidated Condensed Statements of Cash Flows for the Three Months Ended
March 31, 2004 and 2003............................................................................ 7
Notes to Consolidated Condensed Financial Statements................................................. 9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 34
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................. 58
Item 4. Controls and Procedures................................................................................ 58
PART II - OTHER INFORMATION
Item 1. Legal Proceedings...................................................................................... 58
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities....................... 64
Item 6. Exhibits and Reports on Form 8-K....................................................................... 65
Signatures.......................................................................................................... 70
-2-
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
March 31, 2004 and December 31, 2003
(in thousands, except share and per share amounts)
March 31, December 31,
2004 2003
--------------- --------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents................................................. $ 582,804 $ 991,806
Accounts receivable, net.................................................. 1,015,986 988,947
Margin deposits and other prepaid expense................................. 456,857 385,348
Inventories............................................................... 127,998 139,654
Restricted cash........................................................... 401,187 383,788
Current derivative assets................................................. 579,564 496,967
Current assets held for sale.............................................. -- 651
Other current assets...................................................... 184,057 89,593
-------------- --------------
Total current assets................................................... 3,348,453 3,476,754
-------------- --------------
Restricted cash, net of current portion...................................... 215,137 575,027
Notes receivable, net of current portion..................................... 211,759 213,629
Project development costs.................................................... 146,393 139,953
Investments in power projects and oil and gas properties..................... 417,978 472,749
Deferred financing costs..................................................... 439,941 400,732
Prepaid lease, net of current portion........................................ 425,846 414,058
Property, plant and equipment, net........................................... 20,736,669 20,081,052
Goodwill, net................................................................ 45,160 45,160
Other intangible assets, net................................................. 89,753 89,924
Long-term derivative assets.................................................. 753,124 673,979
Long-term assets held for sale............................................... -- 112,148
Other assets................................................................. 531,825 608,767
-------------- --------------
Total assets........................................................... $ 27,362,038 $ 27,303,932
============== ==============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................................... $ 1,007,405 $ 938,644
Accrued payroll and related expense....................................... 56,124 96,693
Accrued interest payable.................................................. 295,632 321,176
Income taxes payable...................................................... 9,563 18,026
Notes payable and borrowings under lines of credit, current portion....... 254,067 254,292
Preferred interests, current portion...................................... 11,597 11,220
Capital lease obligation, current portion................................. 4,396 4,008
CCFC I financing, current portion......................................... 3,208 3,208
Construction/project financing, current portion........................... 76,332 61,900
Senior notes and term loans, current portion.............................. 14,500 14,500
Current derivative liabilities............................................ 551,191 456,688
Other current liabilities................................................. 269,291 319,339
-------------- --------------
Total current liabilities.............................................. 2,553,306 2,499,694
-------------- --------------
Notes payable and borrowings under lines of credit, net of current portion... 791,700 873,572
Notes payable to Calpine Capital Trusts...................................... 1,153,500 1,153,500
Preferred interests, net of current portion.................................. 228,014 232,412
Capital lease obligation, net of current portion............................. 192,340 193,741
CCFC I financing, net of current portion..................................... 784,258 785,781
CalGen/CCFC II financing..................................................... 2,393,945 2,200,358
Construction/project financing, net of current portion....................... 1,548,262 1,209,505
Convertible Senior Notes Due 2006............................................ 72,126 660,059
Convertible Senior Notes Due 2023............................................ 900,000 650,000
Senior notes and term loans, net of current portion.......................... 9,357,521 9,369,253
Deferred income taxes, net................................................... 1,256,416 1,326,044
Deferred lease incentive..................................................... 49,352 50,228
Deferred revenue............................................................. 111,864 116,001
Long-term derivative liabilities............................................. 750,810 692,088
Long-term derivative liabilities held for sale............................... -- 161
Other liabilities............................................................ 269,908 259,390
-------------- --------------
Total liabilities...................................................... 22,413,322 22,271,787
-------------- --------------
Minority interests........................................................... 365,354 410,892
-------------- --------------
-3-
March 31, December 31,
2004 2003
--------------- --------------
(Unaudited)
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000 shares;
none issued and outstanding in 2004 and 2003............................ -- --
Common stock, $.001 par value per share; authorized 1,000,000,000 shares;
issued and outstanding 415,736,644 shares in 2004 and
415,010,125 shares in 2003.............................................. 416 415
Additional paid-in capital................................................ 3,002,075 2,995,735
Retained earnings......................................................... 1,497,317 1,568,509
Accumulated other comprehensive income.................................... 83,554 56,594
-------------- --------------
Total stockholders' equity............................................. $ 4,583,362 $ 4,621,253
-------------- --------------
Total liabilities and stockholders' equity............................. $ 27,362,038 $ 27,303,932
============== ==============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
-4-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2004 and 2003
Three Months Ended
March 31,
--------------------------------
2004 2003
-------------- --------------
(In thousands, except
per share amounts)
(Unaudited)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue.......................................... $ 1,245,887 $ 1,103,535
Sales of purchased power for hedging and optimization.................. 380,028 681,284
-------------- --------------
Total electric generation and marketing revenue...................... 1,625,915 1,784,819
Oil and gas production and marketing revenue
Oil and gas sales...................................................... 24,581 25,911
Sales of purchased gas for hedging and optimization.................... 352,737 327,468
-------------- --------------
Total oil and gas production and marketing revenue................... 377,318 353,379
Mark-to-market activities, net............................................ 12,518 20,443
Other revenue............................................................. 26,987 7,292
-------------- --------------
Total revenue...................................................... 2,042,738 2,165,933
-------------- --------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense................................................ 175,834 161,929
Transmission purchase expense.......................................... 16,427 8,825
Royalty expense........................................................ 5,881 5,357
Purchased power expense for hedging and optimization................... 374,939 679,949
-------------- --------------
Total electric generation and marketing expense...................... 573,081 856,060
Oil and gas operating and marketing expense
Oil and gas operating expense.......................................... 22,328 25,661
Purchased gas expense for hedging and optimization..................... 360,486 316,948
-------------- --------------
Total oil and gas operating and marketing expense.................... 382,814 342,609
Fuel expense.............................................................. 762,705 635,369
Depreciation, depletion and amortization expense.......................... 149,415 133,815
Operating lease expense................................................... 27,799 27,692
Other cost of revenue..................................................... 26,380 5,251
-------------- --------------
Total cost of revenue.............................................. 1,922,194 2,000,796
-------------- --------------
Gross profit.................................................... 120,544 165,137
(Income) from unconsolidated investments in power projects
and oil and gas properties................................................. (2,506) (5,125)
Equipment cancellation and impairment cost................................... 2,360 87
Project development expense.................................................. 7,717 5,086
Research and development expense............................................. 3,815 2,391
Sales, general and administrative expense.................................... 57,247 43,658
-------------- --------------
Income from operations.................................................... 51,911 119,040
Interest expense............................................................. 254,792 142,961
Distributions on trust preferred securities.................................. -- 15,657
Interest (income)............................................................ (12,060) (8,035)
Minority interest expense.................................................... 8,435 2,277
Other expense (income)....................................................... (19,258) 34,590
-------------- --------------
Loss before (benefit) for income taxes.................................... (179,998) (68,410)
(Benefit) for income taxes................................................... (85,949) (16,872)
-------------- --------------
Loss before discontinued operations and cumulative effect
of a change in accounting principle..................................... (94,049) (51,538)
Discontinued operations, net of tax provision (benefit) of $12,325
and $(790)................................................................. 22,857 (1,007)
Cumulative effect of a change in accounting principle,
net of tax provision of $--and $450........................................ -- 529
-------------- --------------
Net loss........................................................ $ (71,192) $ (52,016)
============== ==============
-5-
Three Months Ended
March 31,
--------------------------------
2004 2003
-------------- --------------
(In thousands, except
per share amounts)
(Unaudited)
Basic and diluted loss per common share:
Weighted average shares of common stock outstanding....................... 415,308 380,960
Loss before discontinued operations and cumulative
effect of a change in accounting principle.............................. $ (0.23) $ (0.14)
Discontinued operations, net of tax....................................... $ 0.06 $ --
Cumulative affect of a change in accounting principle, net of tax......... $ -- $ --
-------------- --------------
Net loss........................................................ $ (0.17) $ (0.14)
============== ==============
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
-6-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003
(in thousands)
(unaudited)
Three Months Ended
March 31,
--------------------------------
2004 2003
-------------- --------------
Cash flows from operating activities:
Net loss.................................................................. $ (71,192) $ (52,016)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depreciation, depletion and amortization (1)......................... 197,183 164,501
Deferred income taxes, net........................................... (98,142) 4,597
Tax refund received.................................................. 592 16,952
(Gain) on sale of assets............................................. (32,211) --
Stock compensation expense........................................... 4,266 4,490
Foreign exchange (gains) losses...................................... (9,984) 25,209
Change in net derivative assets and liabilities...................... (36,230) 54,290
Income from unconsolidated investments in power projects
and oil and gas properties......................................... (2,506) (5,125)
Distributions from unconsolidated investments in power projects...... 5,140 9,401
Other................................................................ 7,599 (292)
Change in operating assets and liabilities, net of effects of
acquisitions:
Accounts receivable.................................................. (23,339) (251,833)
Other current assets................................................. (49,708) (81,357)
Other assets......................................................... (6,823) (44,444)
Accounts payable and accrued expense................................. 1,981 281,665
Other liabilities.................................................... (59,856) 39,329
-------------- --------------
Net cash (used in) provided by operating activities................ (173,230) 165,367
-------------- --------------
Cash flows from investing activities:
Purchases of property, plant and equipment................................ (414,945) (507,250)
Disposals of property, plant and equipment................................ 176,914 9,074
Acquisitions, net of cash acquired........................................ (187,466) (6,818)
Advances to joint ventures................................................ (479) (2,020)
Project development costs................................................. (6,837) (8,867)
Decrease in restricted cash............................................... 346,338 16,096
(Increase) decrease in notes receivable................................... 1,772 (4,534)
Other..................................................................... 13,332 20,690
-------------- --------------
Net cash used in investing activities.................................. (71,371) (483,629)
-------------- --------------
Cash flows from financing activities:
Borrowings from notes payable and borrowings under lines of credit........ 2,394,565 --
Repayments of notes payable and borrowings under lines of credit.......... (86,783) --
Borrowings from project financing......................................... 315,142 19,426
Repayments of project financing........................................... (2,343,403) --
Repayments of senior notes................................................ (14,759) --
Repurchase of 4% convertible senior notes................................. (586,926) --
Proceeds from issuance of 4.75% convertible senior notes.................. 250,000 --
Proceeds from income trust offering....................................... -- 100,900
Financing costs........................................................... (75,727) (6,941)
Other..................................................................... (12,200) (842)
-------------- --------------
Net cash (used in) provided by financing activities.................... (160,091) 112,543
-------------- --------------
Effect of exchange rate changes on cash and cash equivalents................. (4,310) 4,290
Net decrease in cash and cash equivalents.................................... (409,002) (201,429)
Cash and cash equivalents, beginning of period............................... 991,806 579,486
-------------- --------------
Cash and cash equivalents, end of period..................................... $ 582,804 $ 378,057
============== ==============
Cash paid during the period for:
Interest, net of amounts capitalized...................................... $ 238,954 $ 71,297
Income taxes.............................................................. $ 15,361 $ 8,003
- ----------
<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.
</FN>
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
-7-
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 2004
(unaudited)
1. Organization and Operations of the Company
Calpine Corporation ("Calpine" or "the Company"), a Delaware corporation,
and subsidiaries (collectively, also referred to as the "Company") are engaged
in the generation of electricity in the United States of America, Canada and the
United Kingdom. The Company is involved in the development, construction,
ownership and operation of power generation facilities and the sale of
electricity and its by-product, thermal energy, primarily in the form of steam.
The Company has ownership interests in, and operates, gas-fired power generation
and cogeneration facilities, gas fields, gathering systems and gas pipelines,
geothermal steam fields and geothermal power generation facilities in the United
States of America. In Canada, the Company owns oil and gas operations and has
ownership interests in, and operates, power facilities. In the United Kingdom,
the Company owns and operates a gas-fired power cogeneration facility. Each of
the generation facilities produces and markets electricity for sale to utilities
and other third party purchasers. Thermal energy produced by the gas-fired power
cogeneration facilities is primarily sold to industrial users. Gas produced, and
not physically delivered to the Company's generating plants, is sold to third
parties.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying unaudited interim
Consolidated Condensed Financial Statements of the Company have been prepared by
the Company pursuant to the rules and regulations of the Securities and Exchange
Commission. In the opinion of management, the Consolidated Condensed Financial
Statements include the adjustments necessary to present fairly the information
required to be set forth therein. Certain information and note disclosures
normally included in financial statements prepared in accordance with generally
accepted accounting principles in the United States of America have been
condensed or omitted from these statements pursuant to such rules and
regulations and, accordingly, these financial statements should be read in
conjunction with the audited Consolidated Financial Statements of the Company
for the year ended December 31, 2003, included in the Company's Annual Report on
Form 10-K. The results for interim periods are not necessarily indicative of the
results for the entire year.
Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expense during the reporting
period. Actual results could differ from those estimates. The most significant
estimates with regard to these financial statements relate to useful lives and
carrying values of assets (including the carrying value of projects in
development, construction retirement and operation), provision for income taxes,
fair value calculations of derivative instruments and associated reserves,
capitalization of interest, primary beneficiary determination for the Company's
investments in variable interest entities, the outcome of pending litigation and
estimates of oil and gas reserves used to calculate depletion, depreciation and
impairment of natural gas and petroleum property and equipment.
Effective Tax Rate -- For the three months ended March 31, 2004, the
effective rate increased to 48% as compared to 25% for the three months ended
March 31, 2003. This effective rate variance is due to the consideration of
estimated year-end earnings in estimating the quarterly effective rate and due
to the effect of significant permanent non-taxable items.
Derivative Instruments -- Financial Accounting Standards Board ("FASB")
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS No. 133") as amended and
interpreted by other related accounting literature, establishes accounting and
reporting standards for derivative instruments (including certain derivative
instruments embedded in other contracts). SFAS No. 133 requires companies to
record derivatives on their balance sheets as either assets or liabilities
measured at their fair value unless exempted from derivative treatment as a
normal purchase and sale. All changes in the fair value of derivatives are
recognized currently in earnings unless specific hedge criteria are met, which
requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting.
Accounting for derivatives at fair value requires the Company to make
estimates about future prices during periods for which price quotes are not
available from sources external to the Company. As a result, the Company is
required to rely on internally developed price estimates when external price
quotes are unavailable. The Company derives its future price estimates, during
periods where external price quotes are unavailable, based on an extrapolation
of prices from periods where external price quotes are available. The Company
-8-
performs this extrapolation using liquid and observable market prices and
extending those prices to an internally generated long-term price forecast based
on a generalized equilibrium model.
SFAS No. 133 sets forth the accounting requirements for cash flow and fair
value hedges. SFAS No. 133 provides that the effective portion of the gain or
loss on a derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period during which the hedged forecasted
transaction affects earnings. The remaining gain or loss on the derivative
instrument, if any, must be recognized currently in earnings. SFAS No. 133
provides that the changes in fair value of derivatives designated as fair value
hedges and the corresponding changes in the fair value of the hedged risk
attributable to a recognized asset, liability, or unrecognized firm commitment
be recorded in earnings. If the fair value hedge is effective, the amounts
recorded will offset in earnings.
With respect to cash flow hedges, if the forecasted transaction is no
longer probable of occurring, the associated gain or loss recorded in other
comprehensive income is recognized currently. In the case of fair value hedges,
if the underlying asset, liability or firm commitment being hedged is disposed
of or otherwise terminated, the gain or loss associated with the underlying
hedged item is recognized currently. If the hedging instrument is terminated
prior to the occurrence of the hedged forecasted transaction for cash flow
hedges or the settlement of the hedged asset, liability or firm commitment for
fair value hedges, the gain or loss associated with the hedge instrument remains
deferred.
Where the Company's derivative instruments are subject to a master netting
agreement and the criteria of FASB Interpretation ("FIN") 39 "Offsetting of
Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10
and SFAS No. 105)" are met, the Company presents its derivative assets and
liabilities on a net basis in its balance sheet. The Company has chosen this
method of presentation because it is consistent with the way related
mark-to-market gains and losses on derivatives are recorded in its Consolidated
Statements of Operations and within Other Comprehensive Income ("OCI").
Mark-to-Market Activity, Net -- This includes realized settlements of and
unrealized mark-to-market gains and losses on both power and gas derivative
instruments undesignated as cash flow hedges, including those held for trading
purposes. Gains and losses due to ineffectiveness on hedging instruments are
also included in unrealized mark-to-market gains and losses. Trading activity is
presented net in accordance with Emerging Issues Task Force ("EITF") Issue No.
02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and
Risk Management Activities" ("EITF Issue No. 02-3").
Presentation of Revenue Under EITF Issue No. 03-11 "Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to 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") -- 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 as a matter of scheduling convenience to eliminate the need to
schedule actual power delivery or "book out" the physical power flows. 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 $370.5 million of purchased power expense against sales of purchased
power during the three months ended March 31, 2004.
New Accounting Pronouncements
On January 1, 2003, the Company prospectively adopted the fair value method
of accounting for stock-based employee compensation pursuant to SFAS No. 123,
"Accounting for Stock-Based Compensation" ("SFAS No. 123") as amended by SFAS
No. 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure"
("SFAS No. 148"). SFAS No. 148 amends SFAS No. 123 to provide alternative
methods of transition for companies that voluntarily change their accounting for
stock-based compensation from the less preferred intrinsic value based method to
the more preferred fair value based method. Prior to its amendment, SFAS No. 123
required that companies enacting a voluntary change in accounting principle from
the intrinsic value methodology provided by Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees" could only do so on a
prospective basis; no adoption or transition provisions were established to
allow for a restatement of prior period financial statements. SFAS No. 148
provides two additional transition options to report the change in accounting
principle -- the modified prospective method and the retroactive restatement
-9-
method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS
No. 123 to require prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results. The Company has elected
to adopt the provisions of SFAS No. 123 on a prospective basis; consequently,
the Company is required to provide a pro-forma disclosure of net income and
earnings per share as if SFAS No. 123 accounting had been applied to all prior
periods presented within its financial statements. As shown below, the adoption
of SFAS No. 123 has had a material impact on the Company's financial statements.
The table below reflects the pro forma impact of stock-based compensation on the
Company's net income and earnings per share for the three months ended March 31,
2004 and 2003, had the Company applied the accounting provisions of SFAS No. 123
to its prior years' financial statements (in thousands, except per share
amounts):
Three Months Ended
March 31,
---------------------------
2004 2003
------------ ------------
Net income
As reported.................................................................. $ (71,192) $ (52,016)
Pro Forma.................................................................... (72,839) (58,452)
Earnings per share data:
Basic earnings per share
As reported............................................................... $ (0.17) $ (0.14)
Pro Forma................................................................. (0.18) (0.15)
Diluted earnings per share
As reported............................................................... $ (0.17) $ (0.14)
Pro Forma................................................................. (0.18) (0.15)
Stock-based compensation cost, net of tax, included in net income, as reported.. $ 2,581 $ 3,367
Stock-based compensation cost, net of tax, included in net income, pro forma.... 4,228 9,803
The range of fair values of the Company's stock options granted for the
three months ended March 31, 2004 and 2003, respectively, was as follows, based
on varying historical stock option exercise patterns by different levels of
Calpine employees: $3.37-$4.45 in 2004, $1.60-$3.43 in 2003, on the date of
grant using the Black-Scholes option pricing model with the following
weighted-average assumptions: expected dividend yields of 0%, expected
volatility of 69.78%-97.99% and 70.44%-97.19% for the three months ended March
31, 2004 and 2003, respectively, risk-free interest rates of 2.35%-4.14% and
1.76%-4.04% for the three months ended March 31, 2004 and 2003, respectively,
and expected option terms of 4-9 1/2 years and 2 1/2-9 1/2 years for the three
months ended March 31, 2004 and 2003, respectively.
In January 2003 FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). FIN 46
requires the consolidation of an entity by an enterprise that absorbs a majority
of the entity's expected losses, receives a majority of the entity's expected
residual returns, or both, as a result of ownership, contractual or other
financial interest in the entity. Historically, entities have generally been
consolidated by an enterprise when it has a controlling financial interest
through ownership of a majority voting interest in the entity. The objectives of
FIN 46 are to provide guidance on the identification of Variable Interest
Entities ("VIEs") for which control is achieved through means other than
ownership of a majority of the voting interest of the entity, and how to
determine which business enterprise (if any), as the Primary Beneficiary, should
consolidate the Variable Interest Entity ("VIE"). This new model for
consolidation applies to an entity in which either (1) the at-risk equity is
insufficient to absorb expected losses without additional subordinated financial
support or (2) its at-risk equity holders as a group are not able to make
decisions that have a significant impact on the success or failure of the
entity's ongoing activities. A variable interest in a VIE, by definition, is an
asset, liability, equity, contractual arrangement or other economic interest
that absorbs the entity's variability.
In December 2003 FASB modified FIN 46 with FIN 46-R to make certain
technical corrections and to address certain implementation issues. FIN 46, as
originally issued, was effective immediately for VIEs created or acquired after
January 31, 2003. FIN 46-R delayed the effective date of the interpretation to
no later than March 31, 2004, (for calendar-year enterprises), except for
Special Purpose Entities ("SPEs") for which the effective date was December 31,
2003. The Company has adopted FIN 46-R for its investment in SPEs, equity method
joint ventures, its wholly owned subsidiaries that are subject to long-term
power purchase agreements and tolling arrangements, operating lease arrangements
containing fixed price purchase options and its wholly owned subsidiaries that
have issued mandatorily redeemable non-controlling preferred interests.
The Company evaluated its investments in joint ventures and operating lease
arrangements containing fixed price purchase options and concluded that, in some
instances, these entities were VIEs. However, in these instances, the Company
-10-
was not the Primary Beneficiary, as the Company would not absorb a majority of
these entities' expected variability. The fixed price purchase options under the
Company's operating lease arrangements were not considered significant variable
interests. However, the Company's investments in joint ventures were considered
significant. See Note 7 for more information related to these joint venture
investments.
An analysis was performed for 100% Company-owned subsidiaries with
significant long-term power sales or tolling agreements. Certain of the 100%
Company-owned subsidiaries were deemed to be VIEs by virtue of a power sales or
tolling agreement which was longer than 10 years and for more than 50% of the
entity's capacity. However, in all cases, the Company absorbed a majority of the
entity's variability and continues to consolidate these 100% Company-owned
subsidiaries. The Company qualitatively determined that power sales or tolling
agreements less than 10 years in length and for less than 50% of the entity's
capacity would not cause the power purchaser to be the Primary Beneficiary, due
to the length of the economic life of the underlying assets. Also, power sales
and tolling agreements meeting the definition of a lease under EITF Issue No.
01-08, "Determining Whether an Arrangement Contains a Lease," were not
considered variable interests, because payments under these leasing arrangements
create rather than absorb the entity's variability.
A similar analysis was performed for the Company's wholly owned
subsidiaries that have issued mandatorily redeemable non-controlling preferred
interests. These entities were determined to be VIEs in which the Company
absorbs the majority of the variability, primarily due to the debt
characteristics of the preferred interest, which are classified as debt in
accordance with SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" in the Company's Consolidated
Condensed Balance Sheets. Consequently, the Company continues to consolidate
these wholly owned subsidiaries.
Significant judgment was required in making an assessment of whether or not
a VIE was a special purpose entity ("SPE") for purposes of adopting and applying
FIN 46-R, as of October 31, 2003. Entities that meet the definition of a
business outlined in FIN 46-R and that satisfy other formation and involvement
criteria are not subject to the FIN 46-R consolidation guidelines. The
definitional characteristics of a business include having: inputs such as
long-lived assets; the ability to obtain access to necessary materials and
employees; processes such as strategic management, operational process and
resource management; and the ability to obtain access to the customers that
purchase the outputs of the entity. Since the current accounting literature does
not provide a definition of an SPE, the Company's assessment was primarily based
on the degree to which the VIE aligned with the definition of a business. Based
on this assessment, the Company determined that five VIE investments were in
SPEs: Calpine Northbrook Energy Marketing, LLC ("CNEM"), Power Contract
Financing, L.L.C. ("PCF") and the Calpine Capital Trusts I, II and III, and
subject to FIN 46-R as of October 1, 2003.
On May 15, 2003, the Company's wholly owned subsidiary, CNEM, completed the
$82.8 million monetization of an existing power sales agreement with the
Bonneville Power Administration ("BPA"). CNEM borrowed $82.8 million secured by
the spread between the BPA contract and certain fixed power purchase contracts.
CNEM was established as a bankruptcy-remote entity and the $82.8 million loan is
recourse only to CNEM's assets and is not guaranteed by the Company. CNEM was
determined to be a VIE in which the Company was the Primary Beneficiary.
Accordingly, the entity's assets and liabilities were consolidated into the
Company's accounts as of June 30, 2003.
On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of Calpine
Energy Services, L.P. ("CES"), completed an offering of two tranches of Senior
Secured Notes Due 2006 and 2010 (collectively called the "PCF Notes"), totaling
$802.2 million. To facilitate the transaction, the Company formed PCF as a
wholly owned, bankruptcy remote entity with assets and liabilities consisting of
certain transferred power purchase and sales contracts, which serve as
collateral for the PCF Notes. The PCF Notes are non-recourse to the Company's
other consolidated subsidiaries. PCF was determined to be a VIE in which the
Company was the Primary Beneficiary. Accordingly, the entity's assets and
liabilities were consolidated into the Company's accounts as of June 30, 2003.
Upon adoption of FIN 46-R for the Company's investments in SPEs, the
Company determined that its equity investment in Calpine Capital Trusts I, II
and III ("the Trusts") was not considered at-risk as defined in FIN 46-R and
that the Company did not have a significant variable interest in the Trusts.
Consequently, the Company deconsolidated the Trusts.
3. Collateral Debt Securities;
In connection with the plans of the Calpine Power Income Fund ("CPIF") to
acquire the King City Power Plant (see Note 15 for more information regarding
this transaction) and become the lessor of the facility, the Company intends to
sell certain investments previously accounted for as held-to-maturity. The table
below reflects the reclassification of the collateral securities from
held-to-maturity to available-for-sale in accordance with SFAS No. 115,
-11-
"Accounting for Certain Investments in Debt and Equity Securities" ("SFAS No.
115"). The following securities were, therefore, recorded at fair market value
in Other Current Assets at March 31, 2004, with the excess over amortized cost
recorded in Other Comprehensive Income (in thousands):
March 31, 2004
---------------------------------------------------------
Gross Gross
Unrealized Unrealized
Gains in Other Losses in Other
Amortized Comprehensive Comprehensive Fair
Cost Income Income Value
--------- -------------- --------------- --------
Corporate debt securities.......................... $12,422 $ 432 $ -- $ 12,854
U.S. Treasury Notes................................ 1,973 142 -- 2,115
U.S. Treasury Securities (non-interest bearing) ... 67,871 17,481 -- 85,352
------- ------- ------- --------
Debt securities................................. $82,266 $18,055 $ -- $100,321
======= ======= ======= ========
4. Property, Plant and Equipment, Net and Capitalized Interest;
As of March 31, 2004 and December 31, 2003, the components of property,
plant and equipment, net, are stated at cost less accumulated depreciation and
depletion as follows (in thousands):
March 31, December 31,
2004 2003
-------------- --------------
Buildings, machinery, and equipment............... $ 13,795,049 $ 13,226,310
Oil and gas properties, including pipelines....... 2,112,964 2,136,740
Geothermal properties............................. 464,795 460,602
Other............................................. 263,197 234,932
-------------- --------------
16,636,005 16,058,584
Less: accumulated depreciation and depletion...... (1,948,872) (1,834,701)
-------------- --------------
14,687,133 14,223,883
Land.............................................. 97,139 95,037
Construction in progress.......................... 5,952,397 5,762,132
-------------- --------------
Property, plant and equipment, net................ $ 20,736,669 $ 20,081,052
============== ==============
Capital Spending -- Construction and Development
Construction and Development costs in process consisted of the following at
March 31, 2004 (in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment
-------- ---------- ----------- ----------- ----------
Projects in active construction.................... 13 $4,684,403 $1,537,067 $ -- $ --
Projects in advanced development................... 15 754,280 623,696 128,708 --
Projects in suspended development.................. 5 463,094 203,185 8,753 --
Projects in early development...................... 3 -- -- 8,932 12,280
Other capital projects............................. NA 50,620 31 -- --
Unassigned ........................................ NA -- -- -- 54,789
---------- ---------- --------- ----------
Total construction and development costs........ $5,952,397 $2,363,979 $ 146,393 $ 67,069
========== ========== ========= ==========
Construction in Progress -- Construction in progress ("CIP") is primarily
attributable to gas-fired power projects under construction including
prepayments on gas and steam turbine generators and other long lead-time items
of equipment for certain development projects not yet in 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 13 projects in active construction
are estimated to come on line from May 2004 to June 2007. These projects will
bring on line approximately 6,495 MW of base load capacity (7,685 MW base load
with peaking capacity). Interest and other costs related to the construction
activities necessary to bring these projects to their intended use are being
-12-
capitalized. At March 31, 2004, the estimated funding requirements to complete
these projects, net of expected project financing proceeds, is approximately
$1.2 billion.
Projects in Advanced Development -- There are 15 projects in advanced
development. These projects will bring on line approximately 6,735 MW of base
load capacity (7,952 MW base load with peaking capacity). Interest and other
costs related to the development activities necessary to bring these projects to
their intended use are being capitalized. However, the capitalization of
interest has been suspended on two projects for which development activities are
complete. The estimated cost to complete the 15 projects in advanced development
is approximately $4.4 billion. The Company's current plan is to commence
construction with project financing, once power purchase agreements are
arranged.
Suspended Development Projects -- Due to current electric market
conditions, the Company has ceased capitalization of additional development
costs and interest expense on certain development projects on which work has
been suspended. Capitalization of costs may recommence as work on these projects
resumes, if certain milestones and criteria are met . These projects would bring
on line approximately 2,569 MW of base load capacity(3,029 MW base load with
peaking capacity). The estimated cost to complete the five projects is
approximately $1.5 billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then all costs, including interest costs are expensed. The
projects in early development with capitalized costs relate to three projects
and include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development as well as software developed for internal use.
Unassigned Equipment -- As of March 31, 2004, the Company had made progress
payments on 4 turbines, 1 heat recovery steam generator and other equipment with
an aggregate carrying value of $67.1 million This unassigned equipment is
classified on the balance sheet as other assets because it is not assigned to
specific development and construction projects. The Company is holding this
equipment for potential use on future projects. It is possible that some of this
unassigned equipment may eventually be sold, potentially in combination with the
Company's engineering and construction services. For equipment that is not
assigned to development or construction projects, interest is not capitalized.
Capitalized Interest -- The Company capitalizes interest on capital
invested in projects during the advanced stages of development and the
construction period in accordance with SFAS No. 34, "Capitalization of Interest
Cost" ("SFAS No. 34"), as amended by SFAS No. 58, "Capitalization of Interest
Cost in Financial Statements That Include Investments Accounted for by the
Equity Method (an Amendment of FASB Statement No. 34)" ("SFAS No. 58"). The
Company's qualifying assets include construction in progress, certain oil and
gas properties under development, construction costs related to unconsolidated
investments in power projects under construction, and advanced stage development
costs. For the three months ended March 31, 2004 and 2003, the total amount of
interest capitalized was $108.5 million and $118.5 million, respectively,
including $18.5 million and $19.6 million, respectively, of interest incurred on
funds borrowed for specific construction projects and $90.0 million and $98.9
million, respectively, of interest incurred on general corporate funds used for
construction. Upon commencement of plant operation, capitalized interest, as a
component of the total cost of the plant, is amortized over the estimated useful
life of the plant. The decrease in the amount of interest capitalized during the
three months ended March 31, 2004 reflects the completion of construction for
several power plants and the result of the current suspension of certain of the
Company's development projects.
In accordance with SFAS No. 34, the Company determines which debt
instruments best represent a reasonable measure of the cost of financing
construction assets in terms of interest cost incurred that otherwise could have
been avoided. These debt instruments and associated interest cost are included
in the calculation of the weighted average interest rate used for capitalizing
interest on general funds. The primary debt instruments included in the rate
calculation of interest incurred on general corporate funds, are certain of the
Company's Senior Notes and term loan facilities and the secured working capital
revolving credit facility.
Impairment Evaluation -- All 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
-13-
of SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets"
("SFAS No. 144"). The Company reviews its unassigned equipment for potential
impairment based on probability-weighted alternatives of utilizing the equipment
for future projects versus selling the equipment. Utilizing this methodology,
the Company does not believe that the equipment not committed to sale is
impaired.
5. Acquisitions
On March 23, 2004, the Company completed the acquisition of the remaining
20% interest in Calpine Cogeneration Company ("Calpine Cogen"), which holds
interests in six power facilities, from NRG Energy, Inc. ("NRG") for
approximately $2.5 million. The Company had purchased its initial 80% interest
in Calpine Cogen (formerly known as Cogeneration Corporation of America) from
NRG in 1999. As a result of the current transaction, the Company now has a 100%
interest in the Newark, Parlin, Morris and Pryor facilities, an 83% interest in
the Philadelphia Water Project, and a 50% interest in the Grays Ferry Power
Plant.
On March 26, 2004, the Company acquired the remaining 50% interest in the
Aries facility from a subsidiary of Aquila, Inc. (Aquila and its subsidiaries
referred to collectively as "Aquila"). At the same time, Aries terminated a
tolling contract with another subsidiary of Aquila. Aquila paid $5 million and
assigned certain transmission and other rights to the Company. Aquila and the
Company also amended a master netting agreement between them, and as a result,
the Company returned cash margin deposits totaling $10.8 million to Aquila.
Contemporaneous with the closing of the acquisition, Aries' existing
construction loan was converted to two term loans totaling $178.8 million. The
Company contributed $15 million of equity to Aries in connection with the term
out of the construction loan.
On March 31, 2004, the Company closed on the purchase of the 570-megawatt,
natural gas-fired, Brazos Valley Power Plant ("Brazos Valley") in Fort Bend
County, Texas, for approximately $175.0 million. The Company used the net
proceeds from the sale of Lost Pines 1 and cash on hand to acquire this facility
in a transaction structured as a tax deferred like-kind exchange under IRS
Section 1031. The consortium of banks that had provided construction financing
for the power plant and had taken possession of the plant from the original
developer in 2003 indirectly owned the special purpose companies that owned
Brazos Valley. Brazos Valley has become part of the collateral package for the
Calpine Construction Finance Company, L.P. ("CCFC I") First Priority Secured
Institutional Term Loans Due 2009 and Second Priority Senior Secured Floating
Rate Notes Due 2011.
6. Financing
On January 9, 2004, one of the initial purchasers of the 4 3/4% Contingent
Convertible Senior Notes Due 2023 ("2023 Convertible Notes") exercised in full
its option to purchase an additional $250.0 million of these notes. The notes
are convertible into cash and into shares of Calpine common stock upon the
occurrence of certain contingencies at an initial conversion price of $6.50 per
share, which represents a 38% premium over the New York Stock Exchange closing
price of $4.71 per share on November 6, 2003, the date the notes were originally
priced. Upon conversion of the notes, the Company will deliver par value in cash
and any additional value in Calpine shares.
During the three months ended March 31, 2004, the Company repurchased
$178.5 million in principal amount of its outstanding 4% Convertible Senior
Notes Due 2006 ("2006 Convertible Senior Notes") that can be put to the Company
in exchange for $177.5 million in cash. Additionally, on February 9, 2004, the
Company made a cash tender offer, which expired on March 9, 2004, for any and
all of the then still outstanding 2006 Convertible Senior Notes at a price of
par plus accrued interest. On March 10, 2004, the Company paid an aggregate
amount of $412.8 million for the tendered 2006 Convertible Senior Notes which
included accrued interest of $3.4 million. At March 31, 2004, 2006 Convertible
Senior Notes in the aggregate principal amount of $72.1 million remain
outstanding.
On February 18, 2004, one of the Company's wholly owned subsidiaries closed
on the sale of natural gas properties to Calpine Natural Gas Trust ("CNG
Trust"). The Company received consideration of Cdn$40.5 million (US$30.9
million). Calpine holds 25% of the outstanding trust units of CNG Trust and
accounts for the investment using the equity method. The Company recorded a $6.2
million pre-tax gain on the sale of these properties.
On February 20, 2004, the Company completed a $250.0 million, non-recourse
project financing for the 600-megawatt Rocky Mountain Energy Center. A
consortium of banks financed the construction of the plant at a rate of LIBOR
plus 250 basis points. Upon commercial operation of the Rocky Mountain Energy
Center, the banks will provide a three-year term-loan facility.
On March 23, 2004, the Company's wholly owned subsidiary Calpine Generating
Company, LLC ("CalGen"), formerly known as Calpine Construction Finance Company
II, LLC ("CCFC II"), completed its offering of secured term loans and secured
-14-
notes. As expected, the Company realized net total proceeds from the offerings
(after payment of transaction fees and expenses, including the fee payable to
Morgan Stanley in connection with an index hedge) in the approximate amount of
$2.3 billion. The offerings included:
Amount Description Interest Rate
- -------------------- ----------------------------------------------------- ------------------------------
$235.0 million First Priority Secured Floating Rate Notes Due 2009 LIBOR plus 375 basis points
$640.0 million Second Priority Secured Floating Rate Notes Due 2010 LIBOR plus 575 basis points
$680.0 million Third Priority Secured Floating Rate Notes Due 2011 LIBOR plus 900 basis points
$150.0 million Third Priority Secured Notes Due 2011 11.50%
$600.0 million First Priority Secured Term Loans due 2009 LIBOR plus 375 basis points(1)
$100.0 million Second Priority Secured Term Loans due 2010 LIBOR plus 575 basis points(2)
- ----------
<FN>
(1) The Company may also elect a Base Rate plus 275 basis points.
(2) The Company may also elect a Base Rate plus 475 basis points.
</FN>
The secured term loans and secured notes described above in each case are
collateralized, through a combination of pledges of the equity interests in
CalGen and its first tier subsidiary, CalGen Expansion Company, liens on the
assets of CalGen's power generating facilities (other than its Goldendale
facility) and related assets located throughout the United States. The lenders'
recourse is limited to such collateral, and none of the indebtedness is
guaranteed by Calpine. Net proceeds from the offerings were used to refinance
amounts outstanding under the $2.5 billion CCFC II revolving construction credit
facility, which was scheduled to mature in November 2004, and to pay fees and
transaction costs associated with the refinancing. Concurrently with this
refinancing, the Company amended and restated the CCFC II credit facility (as
amended and restated, the "CalGen revolving credit facility") to reduce the
commitments under the facility to $200.0 million and extend its maturity to
March 2007. Borrowings under the CalGen revolving credit facility bear interest
at LIBOR plus 350 basis points (or, at the Company's election, the Base Rate
plus 250 basis points). Outstanding indebtedness and letters of credit under the
CCFC II credit facility at December 31, 2003, and at the refinancing date,
totaled approximately $2.3 billion and $2.4 billion, respectively.
On March 24, 2004, the Company repurchased $9.0 million in principal amount
of its outstanding 8 1/2% Senior Notes Due 2011 and $11.0 million in principal
amount of its outstanding 7 3/4% Senior Notes Due 2009, in exchange for
approximately $14.8 million in cash. A gain of $5.0 million, net of deferred
financing costs written off, was recognized in the first quarter of 2004.
Annual Debt Maturities
The annual principal repayments or maturities of notes payable and
borrowings under lines of credit, notes payable to Calpine Capital Trusts,
preferred interests, construction/project financing, 2006 Convertible Senior
Notes, 2023 Convertible Notes, senior notes and term loans, CCFC I financing,
CalGen/CCFC II financing and capital lease obligations as of March 31, 2004, are
as follows (in thousands):
April through December 2004................ $ 245,934
2005....................................... 526,637
2006....................................... 775,461
2007....................................... 2,371,194
2008....................................... 2,620,659
Thereafter................................. 11,245,881
-------------
Total................................... $ 17,785,766
=============
7. Investments in Power Projects and Oil and Gas Properties
The Company's investments in power projects and oil and gas properties are
integral to its operations. As discussed in Note 2, the Company's joint venture
investments were evaluated under FIN 46-R to determine which, if any, entities
were VIEs. Based on this evaluation, the Company determined that the Acadia
Energy Center, Grays Ferry Power Plant, Whitby Cogeneration facility and the
Androscoggin Power Plant were VIEs, in which the Company held a significant
variable interest. However, based on a qualitative and quantitative assessment
of the expected variability in these entities, the Company was not the primary
beneficiary. Consequently, the Company continues to account for these VIEs and
its other joint venture investments in power projects in accordance with APB
Opinion No. 18, "The Equity Method of Accounting For Investments in Common
Stock" and FASB Interpretation No. 35, "Criteria for Applying the Equity Method
of Accounting for Investments in Common Stock (An Interpretation of APB Opinion
No. 18)."
-15-
Acadia Powers Partners, LLC ("Acadia") is the owner of a 1,160-megawatt
electric wholesale generation facility located in Louisiana and is a joint
venture between the Company and Cleco Corporation. The Company's involvement in
this VIE began upon formation of the entity in March 2000. The Company's maximum
potential exposure to loss at March 31, 2004, is limited to the book value of
its investment of approximately $224.1 million.
Grays Ferry Cogeneration Partnership ("Grays Ferry") is the owner of a
140-megawatt gas-fired cogeneration facility located in Pennsylvania and is a
joint venture between the Company and Trigen-Schuylkill Cogeneration, Inc. The
Company's involvement in this VIE began with its acquisition of the independent
power producer, Cogeneration Corporation of America, Inc. ("Cogen America") in
December 1999. The Grays Ferry joint venture project was part of the portfolio
of assets owned by Cogen America. The Company's maximum potential exposure to
loss at March 31, 2004, is limited to the book value of its investment of
approximately $48.4 million.
Androscoggin Energy LLC ("AELLC") is the owner of a 160-megawatt gas-fired
cogeneration facility located in Maine and is a joint venture between the
Company, Wisvest Corporation and Androscoggin Energy, Inc. The Company's
involvement in this VIE began with its acquisition of the independent power
producer, SkyGen Energy LLC ("SkyGen") in October 2000. The Androscoggin joint
venture project was part of the portfolio of assets owned by SkyGen. The
Company's maximum potential exposure to loss at March 31, 2004, is limited to
$29.0 million, which represents the book value of its investment of
approximately $14.2 million and a notes receivable balance due from AELLC of
$14.8 million as described below.
Whitby Energy LLP ("Whitby") is the owner of a 50-megawatt gas-fired
cogeneration facility located in Ontario, Canada and is a joint venture between
the Company and a privately held enterprise. The Company's involvement in this
VIE began with its acquisition of a portfolio of assets from Westcoast Energy
Inc. ("Westcoast") in September 2001, which included the Whitby joint venture
project. The Company's maximum potential exposure to loss at March 31, 2004, is
limited to the book value of its investment of approximately $35.1 million.
The following investments are accounted for under the equity method (in
thousands):
Ownership Investment Balance at
Interest as of -------------------------
March 31, March 31, December 31,
2004 2004 2003
-------------- ----------- -----------
Acadia Energy Center................................................ 50.0% $ 224,080 $ 221,038
Valladolid III IPP.................................................. 45.0% 69,255 67,320
Grays Ferry Power Plant (1)......................................... 50.0% 48,352 53,272
Whitby Cogeneration................................................. 20.8% 35,083 31,033
Calpine Natural Gas Trust........................................... 25.0% 25,714 28,598
Androscoggin Power Plant............................................ 32.3% 14,174 11,823
Aries Power Plant (2)............................................... 100.0% -- 58,205
Other............................................................... -- 1,320 1,460
----------- -----------
Total investments in power projects and oil and gas properties... $ 417,978 $ 472,749
=========== ===========
- ----------
<FN>
(1) On March 23, 2004, the Company completed the acquisition of the remaining
20% interest in Calpine Cogen. As a result of the acquisition, the
Company's ownership percentage in the Grays Ferry Power Plant increased to
50%. See Note 5 for information on the acquisition.
(2) On March 26, 2004, the Company acquired the remaining 50 percent interest
in Aries Power Plant. Accordingly, this plant is consolidated as of March
31, 2004. See Note 5 for information on the acquisition.
</FN>
The debt on the books of the unconsolidated power projects is not reflected
on the Company's Consolidated Condensed Balance Sheets. At March 31, 2004,
investee debt is approximately $289.6 million. Based on the Company's pro rata
ownership share of each of the investments, the Company's share would be
approximately $61.5 million. However, all such debt is non-recourse to the
Company.
The Company owns a 32.3% interest in the unconsolidated equity method
investee AELLC. AELLC owns the 160-MW Androscoggin Energy Center located in
Maine and has construction debt of $60.1 million outstanding as of March 31,
2004. The debt is non-recourse to Calpine Corporation (the "AELLC Non-Recourse
Financing"). On March 31, 2004, and December 31, 2003, the Company's investment
balance was $14.2 million and $11.8 million, respectively, and its notes
-16-
receivable balance due from AELLC was $14.8 million and $13.3 million,
respectively. On and after August 8, 2003, AELLC received letters from the
lenders claiming that certain events of default have occurred under the credit
agreement for the AELLC Non-Recourse Financing, including, among other things,
that the project has been and remains in default under its debt agreement
because the lending syndication had declined to extend the dates for the
conversion of the construction loan to a term loan by a certain date. AELLC
disputes the purported defaults. Also, the steam host for the AELLC project,
International Paper Company ("IP"), filed a complaint against AELLC in October
2000, which is disclosed in Note 12. IP's complaint has been a complicating
factor in converting the construction debt to long term financing. As a result
of these events, the Company has reviewed its investment and notes receivable
balances and believes that the assets are not impaired. The Company further
believes that AELLC will eventually be able to convert the construction loan to
a term loan.
The following details the Company's income and distributions from
investments in unconsolidated power projects and oil and gas properties (in
thousands):
Income (Loss) from
Unconsolidated
Investments in Power Projects
And Oil and Gas Properties Distributions
----------------------------- -----------------------------
For the Three Months Ended March 31,
-------------------------------------------------------------
2004 2003 2004 2003
------------- ------------- ------------- -------------
Acadia Energy Center............................... $ 5,217 $ 7,618 $ 2,193 $ 9,396
Aries Power Plant.................................. (1,589) (2,225) -- --
Grays Ferry Power Plant............................ (1,851) 26 -- --
Whitby Cogeneration................................ 317 638 565 --
Calpine Natural Gas Trust.......................... 1,321 -- 2,313 --
Androscoggin Power Plant........................... (1,252) (2,876) -- --
Gordonsville Power Plant (1)....................... -- 1,910 -- --
Other.............................................. 109 5 69 5
------------- ------------- ------------ -------------
Total........................................... $ 2,272 $ 5,096 $ 5,140 $ 9,401
============= ============= ============ =============
Interest income on notes receivable from
power projects (2)............................... $ 234 $ 29
------------- -------------
Total........................................... $ 2,506 $ 5,125
============= =============
- ----------
<FN>
The Company provides for deferred taxes on its share of earnings.
(1) On November 26, 2003, the Company completed the sale of its 50 percent
interest in the Gordonsville Power Plant.
(2) At March 31, 2004, and December 31, 2003, notes receivable from power
projects represented an outstanding loan to the Company's investment,
Androscoggin Energy Center LLC, in the amounts of $14.8 million and $13.3
million, respectively.
</FN>
Related-Party Transactions
The Company and certain of its equity method affiliates have entered into
various service agreements with respect to power projects and oil and gas
properties. Following is a general description of each of the various
agreements:
Operation and Maintenance Agreements -- The Company operates and maintains
the Acadia Power Plant and Androscoggin Power Plant. This includes routine
maintenance, but not major maintenance, which is typically performed under
agreements with the equipment manufacturers. Responsibilities include
development of annual budgets and operating plans. Payments include
reimbursement of costs, including Calpine's internal personnel and other costs,
and annual fixed fees.
Administrative Services Agreements -- The Company handles administrative
matters such as bookkeeping for certain unconsolidated investments. Payment is
on a cost reimbursement basis, including Calpine's internal costs, with no
additional fee.
Power Marketing Agreements -- Under agreements with the Company's
Androscoggin Power Plant, CES can either market the plant's power as the power
facility's agent or buy the power directly. Terms of any direct purchase are to
-17-
be agreed upon at the time and incorporated into a transaction confirmation.
Historically, CES has generally bought the power from the power facility rather
than acting as its agent.
Gas Supply Agreement -- CES can be directed to supply gas to the
Androscoggin Power Plant facility pursuant to transaction confirmations between
the facility and CES. Contract terms are reflected in individual transaction
confirmations.
The power marketing and gas supply contracts with CES are accounted for as
either purchase and sale arrangements or as tolling arrangements. In a purchase
and sale arrangement, title and risk of loss associated with the purchase of gas
is transferred from CES to the project at the gas delivery point. In a tolling
arrangement, title to fuel provided to the project does not transfer, and CES
pays the project a capacity and a variable fee based on the specific terms of
the power marketing and gas supply agreements. In addition to the contracts
specified above, CES maintains two tolling agreements with the Acadia facility.
All of the other power marketing and gas supply contracts are accounted for
as purchases and sales.
The related party balances as of March 31, 2004 and December 31, 2003,
reflected in the accompanying Consolidated Condensed Balance Sheets, and the
related party transactions for the three months ended March 31, 2004, and 2003,
reflected in the accompanying Consolidated Condensed Statements of Operations
are summarized as follows (in thousands):
March 31, December 31,
2004 2003
-------------- --------------
Accounts receivable.......................... $ 6,821 $ 1,156
Accounts payable............................. 9,985 12,172
Interest receivable.......................... 1,656 2,074
Note Receivable.............................. 14,802 13,262
Other receivables............................ 9,489 8,794
2004 2003
-------------- --------------
For the Three Months Ended March 31,
Revenue...................................... $ 647 $ 455
Cost of Revenue.............................. 32,746 13,387
Maintenance fee revenue...................... 139 143
Interest income.............................. 234 29
Gain on sale of assets....................... 6,240 --
8. Discontinued Operations
Set forth below are all of the Company's asset disposals by reportable
segment that impacted the Company's Consolidated Condensed Financial Statements
as of March 31, 2004 and December 31, 2003:
Corporate and Other
On July 31, 2003, the Company completed the sale of its specialty data
center engineering business and recorded a pre-tax loss on the sale of $11.6
million.
Oil and Gas Production and Marketing
On November 20, 2003, the Company completed the sale of its Alvin South
Field oil and gas assets located near Alvin, Texas for approximately $0.06
million to Cornerstone Energy, Inc. As a result of the sale, the Company
recognized a pre-tax loss of $0.2 million.
Electric Generation and Marketing
On January 15, 2004, the Company completed the sale of its 50-percent
undivided interest in the 545 megawatt Lost Pines 1 Power Project to GenTex
Power Corporation, an affiliate of the Lower Colorado River Authority (LCRA).
Under the terms of the agreement, Calpine received a cash payment of $146.8
million and recorded a 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 or designation as "held for sale" of these oil
and gas and power plant assets and liabilities and to separately classify the
operating results of the assets sold and gain on sale of those assets from the
operating results of continuing operations to discontinued operations.
-18-
The tables below present significant components of the Company's income
from discontinued operations for the three months ended March 31, 2004, and
2003, respectively (in thousands):
Three Months Ended March 31, 2004
------------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------ ------------- -------------
Total revenue................................................ $ 2,679 $ -- $ -- $ 2,679
============= ============ ============= =============
Gain on disposal before taxes................................ $ 35,327 $ -- $ -- $ 35,327
Operating loss from discontinued operations before taxes..... (145) -- -- (145)
------------- ------------ ------------- -------------
Income from discontinued operations before taxes............. $ 35,182 $ -- $ -- 35,182
============= ============ ============= =============
Gain on disposal, net of tax................................. $ 22,951 $ -- $ -- $ 22,951
Operating loss from discontinued operations, net of tax...... (94) -- -- (94)
------------- ------------ ------------- -------------
Income from discontinued operations, net of tax.............. $ 22,857 $ -- $ -- $ 22,857
============= ============ ============= =============
Three Months Ended March 31, 2003
------------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------ ------------- -------------
Total revenue................................................ $ 18,503 $ 78 $ 1,763 $ 20,344
============= ============ ============= =============
Gain on disposal before taxes................................ $ -- $ -- $ -- $ --
Operating income (loss) from discontinued operations
before taxes............................................... 878 30 (2,705) (1,797)
------------- ------------ ------------- -------------
Income (loss) from discontinued operations
before taxes............................................... $ 878 $ 30 $ (2,705) $ (1,797)
============= ============ ============= =============
Gain on disposal, net of tax................................. $ -- $ -- $ -- $ --
Operating income (loss) from discontinued operations,
net of tax................................................. 570 19 (1,596) (1,007)
------------- ------------ ------------- -------------
Income (loss) from discontinued operations, net of tax....... $ 570 $ 19 $ (1,596) $ (1,007)
============= ============ ============= =============
9. Derivative Instruments
Commodity Derivative Instruments
As an independent power producer primarily focused on generation of
electricity using gas-fired turbines, the Company's natural physical commodity
position is "short" fuel (i.e., natural gas consumer) and "long" power (i.e.,
electricity seller). To manage forward exposure to price fluctuation in these
commodities, the Company enters into derivative commodity instruments. The
Company enters into commodity instruments to convert floating or indexed
electricity and gas prices to fixed prices in order to lessen its vulnerability
to reductions in electric prices for the electricity it generates, to reductions
in gas prices for the gas it produces, and to increases in gas prices for the
fuel it consumes in its power plants. The Company seeks to "self-hedge" its gas
consumption exposure to an extent with its own gas production position. The
hedging, balancing, or optimization activities that the Company engages in are
directly related to the Company's asset-based business model of owning and
operating gas-fired electric power plants and are designed to protect the
Company's "spark spread" (the difference between the Company's fuel cost and the
revenue it receives for its electric generation). The Company hedges exposures
that arise from the ownership and operation of power plants and related sales of
electricity and purchases of natural gas, and the Company utilizes derivatives
to optimize the returns the Company is able to achieve from these assets for the
Company's shareholders. From time to time the Company has entered into contracts
considered energy trading contracts under EITF Issue No. 02-3. However, the
Company's traders have low capital at risk and value at risk limits for energy
trading, and its risk management policy limits, at any given time, its net sales
of power to its generation capacity and limits its net purchases of gas to its
fuel consumption requirements on a total portfolio basis. This model is markedly
different from that of companies that engage in significant commodity trading
operations that are unrelated to underlying physical assets. Derivative
commodity instruments are accounted for under the requirements of SFAS No. 133.
-19-
The Company also routinely enters into physical commodity contracts for
sales of its generated electricity and sales of its natural gas production to
ensure favorable utilization of generation and production assets. Such contracts
often meet the criteria of SFAS No. 133 as derivatives but are generally
eligible for the normal purchases and sales exception. Some of those contracts
that are not deemed normal purchases and sales can be designated as hedges of
the underlying consumption of gas or production of electricity.
Interest Rate and Currency Derivative Instruments
The Company also enters into various interest rate swap agreements to hedge
against changes in floating interest rates on certain of its project financing
facilities. The interest rate swap agreements effectively convert floating rates
into fixed rates so that the Company can predict with greater assurance what its
future interest costs will be and protect itself against increases in floating
rates.
In conjunction with its capital markets activities, the Company enters into
various forward interest rate agreements to hedge against interest rate
fluctuations that may occur after the Company has decided to issue long-term
fixed rate debt but before the debt is actually issued. The forward interest
rate agreements effectively prevent the interest rates on anticipated future
long-term debt from increasing beyond a certain level, allowing the Company to
predict with greater assurance what its future interest costs on fixed rate
long-term debt will be.
The Company enters into various foreign currency swap agreements to hedge
against changes in exchange rates on certain of its senior notes denominated in
currencies other than the U.S. dollar. The foreign currency swaps effectively
convert floating exchange rates into fixed exchange rates so that the Company
can predict with greater assurance what its U.S. dollar cost will be for
purchasing foreign currencies to satisfy the interest and principal payments on
these senior notes.
Summary of Derivative Values
The table below reflects the amounts (in thousands) that are recorded as
assets and liabilities at March 31, 2004, for the Company's derivative
instruments:
Commodity
Interest Rate Derivative Total
Derivative Instruments Derivative
Instruments Net Instruments
------------- ------------- -------------
Current derivative assets.................................... $ 6,539 $ 573,025 $ 579,564
Long-term derivative assets.................................. -- 753,124 753,124
------------- ------------- -------------
Total assets.............................................. $ 6,539 $ 1,326,149 $ 1,332,688
============= ============= =============
Current derivative liabilities............................... $ 21,802 $ 529,389 $ 551,191
Long-term derivative liabilities............................. 62,532 688,278 750,810
------------- ------------- -------------
Total liabilities......................................... $ 84,334 $ 1,217,667 $ 1,302,001
============= ============= =============
Net derivative assets (liabilities).................... $ (77,795) $ 108,482 $ 30,687
============= ============= =============
Of the Company's net derivative assets, $393.6 million and $76.4 million
are net derivative assets of Power Contract Financing, LLC and Calpine
Northbrook Energy Marketing, LLC, respectively, each of which is an entity with
its existence separate from the Company and other subsidiaries of the Company,
but both of which are consolidated by the Company pursuant to FIN 46.
At any point in time, it is highly unlikely that total net derivative
assets and liabilities will equal accumulated OCI, net of tax from derivatives,
for three primary reasons:
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.
-20-
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 accumulated OCI
balance remains that is not recognized in earnings until the forecasted
initially hedged transactions occur. As a result, there will be a temporary
difference between OCI and derivative assets and liabilities on the books
until the remaining OCI balance is recognized in earnings.
Below is a reconciliation of the Company's net derivative assets to its
accumulated other comprehensive loss, net of tax from derivative instruments at
March 31, 2004 (in thousands):
Net derivative assets............................................................................. $ 30,687
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness............... (72,727)
Cash flow hedges terminated prior to maturity..................................................... (160,757)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges....... 63,965
Accumulated OCI from unconsolidated investees..................................................... 21,478
-------------
Accumulated other comprehensive loss from derivative instruments, net of tax(1)................... $ (117,354)
=============
- ----------
<FN>
(1) Amount represents one portion of the Company's total accumulated OCI
balance. See Note 10 for further information.
</FN>
The asset and liability balances for the Company's commodity derivative
instruments represent the net totals after offsetting certain assets against
certain liabilities under the criteria of FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB
Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract,
FIN 39 will allow the offsetting of assets against liabilities so long as four
criteria are met: (1) each of the two parties under contract owes the other
determinable amounts; (2) the party reporting under the offset method has the
right to set off the amount it owes against the amount owed to it by the other
party; (3) the party reporting under the offset method intends to exercise its
right to set off; and; (4) the right of set-off is enforceable by law. The table
below reflects both the amounts (in thousands) recorded as assets and
liabilities by the Company and the amounts that would have been recorded had the
Company's commodity derivative instrument contracts not qualified for offsetting
as of March 31, 2004.
March 31, 2004
-----------------------------
Gross Net
------------- -------------
Current derivative assets................ $ 928,478 $ 573,025
Long-term derivative assets.............. 1,161,134 753,124
------------- -------------
Total derivative assets............... $ 2,089,612 $ 1,326,149
============= =============
Current derivative liabilities........... $ 888,778 $ 529,389
Long-term derivative liabilities......... 1,092,352 688,278
------------- -------------
Total derivative liabilities.......... $ 1,981,130 $ 1,217,667
============= =============
Net commodity derivative assets.... $ 108,482 $ 108,482
============= =============
The table above excludes the value of interest rate and currency derivative
instruments.
-21-
The tables below reflect the impact of the Company's derivative instruments
on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the
changes in market value of derivatives not designated as hedges of cash flows,
for the three months ended March 31, 2004 and 2003, respectively (in thousands):
Three Months Ended March 31,
------------------------------------------------------------------------------------------
2004 2003
------------------------------------------- --------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ ---------- --------------- ------------ ----------
Natural gas derivatives(1)........ $ 5,446 $ 637 $ 6,083 $ 6,113 $ (1,977) $ 4,136
Power derivatives(1).............. (540) (10,488) (11,028) (3,026) (1,881) (4,907)
Interest rate derivatives(2)...... (398) 96 (302) (209) -- (209)
-------------- ----------- --------- -------------- ------------ ----------
Total.......................... $ 4,508 $ (9,755) $ (5,247) $ 2,878 $ (3,858) $ (980)
============== =========== ========= ============== ============ ==========
- ----------
<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, 2004 and 2003, respectively (in
thousands):
2004 2003
------------ ------------
Natural gas and crude oil derivatives......... $ 4,934 $ 35,162
Power derivatives............................. 12,768 (51,326)
Interest rate derivatives..................... (2,772) (10,642)
Foreign currency derivatives.................. (516) 12,557
----------- ------------
Total derivatives.......................... $ 14,414 $ (14,249)
=========== ============
As of March 31, 2004 the maximum length of time over which the Company was
hedging its exposure to the variability in future cash flows for forecasted
transactions was 8 and 14 years, for commodity and interest rate derivative
instruments, respectively. The Company estimates that pre-tax losses of $55.9
million would be reclassified from accumulated OCI into earnings during the
twelve months ended March 31, 2005, as the hedged transactions affect earnings
assuming constant gas and power prices, interest rates, and exchange rates over
time; however, the actual amounts that will be reclassified will likely vary
based on the probability that gas and power prices as well as interest rates and
exchange rates will, in fact, change. Therefore, management is unable to predict
what the actual reclassification from OCI to earnings (positive or negative)
will be for the next twelve months.
The table below presents (in thousands) the pre-tax gains (losses)
currently held in OCI that will be recognized annually into earnings, assuming
constant gas and power prices, interest rates, and exchange rates over time.
2009 &
2004 2005 2006 2007 2008 After Total
----------- ----------- ----------- ---------- ---------- ----------- ------------
Gas OCI......................... $ 49,468 $ (893) $ 30,731 $ 1,181 $ 1,060 $ 2,541 $ 84,088
Power OCI....................... (65,443) (64,935) (46,304) (2,037) 31 64 (178,624)
Interest rate OCI............... (13,629) (16,769) (12,060) (8,602) (5,163) (24,021) (80,244)
Foreign currency OCI............ (1,377) (1,879) (1,879) (1,489) 85 -- (6,539)
---------- ---------- ---------- --------- --------- ---------- -----------
Total pre-tax OCI............ $ (30,981) $ (84,476) $ (29,512) $ (10,947) $ (3,987) $ (21,416) $ (181,319)
========== ========== ========== ========= ========= ========== ===========
10. Comprehensive Income (Loss)
Comprehensive income is the total of net income and all other non-owner
changes in equity. Comprehensive income includes the Company's net income ,
unrealized gains and losses from derivative instruments that qualify as cash
flow hedges and the effects of foreign currency translation adjustments. The
-22-
Company reports Accumulated Other Comprehensive Income ("AOCI") in its
Consolidated Balance Sheet. The tables below detail the changes during the three
months ended March 31, 2004 and 2003, 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 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............................... 34,703
Reclassification adjustment for gain included
in net loss for the three months ended March
31, 2004..................................... (14,414)
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
========= ========== ========= ===========
Total
Accumulated Comprehensive
Other Income (Loss)
Foreign Comprehensive for the Three
Cash Flow Currency Income Months Ended
Hedges Translation (Loss) March 31, 2003
--------- ----------- ------------- ---------------
Accumulated other comprehensive loss at January 1, 2003........... $(224,414) $ (13,043) $ (237,457)
Net loss.......................................................... $ (52,016)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the
three months ended March 31, 2003......................... 27,827
Reclassification adjustment for loss included in
net loss for the three months ended March 31, 2003........ 14,249
Income tax provision for the three months
ended March 31, 2003...................................... (10,927)
-------- -----------
31,149 31,149 31,149
Foreign currency translation gain for the three months
ended March 31, 2003...................................... -- 84,062 84,062 84,062
-------- ---------- ----------- ------------
Total comprehensive income for the three months ended
March 31, 2003.................................................. $ 63,195
============
Accumulated other comprehensive loss at March 31, 2003............ $(193,265) $ 71,019 $ (122,246)
========= ========== ===========
11. Loss per Share
Basic loss per common share were computed by dividing net loss by the
weighted average number of common shares outstanding for the respective periods.
The dilutive effect of the potential exercise of outstanding options to purchase
shares of common stock is calculated using the treasury stock method. The
dilutive effect of the assumed conversion of certain convertible securities into
the Company's common stock is based on the dilutive common share equivalents and
the after tax distribution expense avoided upon conversion. The reconciliation
-23-
of basic loss per common share to diluted loss per share is shown in the
following table (in thousands, except per share data).
Periods Ended March 31,
----------------------------------------------------------
2004 2003
---------------------------- ---------------------------
Net Loss Shares EPS Net Loss Shares EPS
--------- ------- ------- -------- ------- -------
THREE MONTHS:
Basic and diluted loss per common share:
Loss before discontinued operations and cumulative
effect of a change in accounting principle.................. $ (94,049) 415,308 $ (0.23) $ (51,538) 380,960 $ (0.14)
Discontinued operations, net of tax........................... 22,857 -- 0.06 (1,007) -- --
Cumulative effect of a change in accounting principle,
net of tax.................................................. -- -- -- 529 -- --
--------- ------- ------- --------- ------- -------
Net loss...................................................... $ (71,192) 415,308 $ (0.17) $ (52,016) 380,960 $ (0.14)
========= ======= ======= ========= ======= =======
Because of the Company's losses for the three months ended March 31, 2004
and 2003, basic shares were used in the calculations of fully diluted loss per
share, under the guidelines of SFAS No. 128, "Earnings per Share," as using the
basic shares produced the more dilutive effect on the loss per share.
Potentially convertible securities and unexercised employee stock options to
purchase 72,565,275 and 115,332,743 shares of the Company's common stock were
not included in the computation of diluted shares outstanding during the three
months ended March 31, 2004 and 2003, respectively, because such inclusion would
be anti-dilutive.
For the quarter ended March 31, 2004, approximately 23.8 million weighted
common shares of the Company's outstanding 4% convertible senior notes due 2006
were excluded from the diluted EPS calculations as the inclusion of such shares
would have been antidilutive. Due to repurchases by the Company of these
securities during the first quarter, at March 31, 2004, 4.0 million common
shares were potentially issuable upon the conversion of 100% of these securities
then outstanding. The holders have the right to require the Company to
repurchase these securities on December 26, 2004, at a repurchase price equal to
the issue price plus any accrued and unpaid interest, payable at the option of
the Company in cash or common shares, or a combination of cash and common
shares.
In connection with the convertible notes payable to Calpine Capital Trust
("Trust I"), Calpine Capital Trust II ("Trust II") and Calpine Capital Trust III
("Trust III"), net of repurchases, there were 16.3 million, 14.1 million and
11.9 million common shares potentially issuable, respectively. These notes are
convertible at any time at the applicable holder's option in connection with the
conversion of convertible preferred securities issued by the Trusts, and may be
redeemed at any time after their respective initial redemption date. The Company
is required to remarket the convertible preferred securities issued by Trust I,
Trust II and Trust III no later than November 1, 2004, February 1, 2005 and
August 1, 2005, respectively. If the Company is not able to remarket those
securities, it will result in additional interest costs and an adjusted
conversion rate equal to 105% of the average closing price of our common stock
for the five consecutive trading days after the failed remarketing.
For the quarter ended March 31, 2004, there were no shares potentially
issuable with respect to the Company's 4.75% contingent convertible senior notes
due 2023. Upon the occurrence of certain contingencies, these securities are
convertible at the holder's option in cash for the face amount and in shares of
the Company's common stock for the appreciated value in the Company's common
stock over $6.50 per share. Holders have the right to require the Company to
repurchase these securities at various times beginning on November 15, 2009, for
the face amount plus any accrued and unpaid interest and liquidated damages, if
any. The repurchase price is payable at the option of the Company in cash or
common shares, or a combination of both. The Company may redeem the related
notes at any time on or after November 22, 2009 in cash for the face amount plus
any accrued and unpaid interest and liquidated damages, if any. Approximately
138.4 million maximum potential shares are issuable upon conversion of these
securities and are excluded from the diluted EPS calculations as there are
currently no shares contingently issuable due to the Company's quarter end stock
price being under $6.50.
12. Commitments and Contingencies
Turbines. The table below sets forth future turbine payments for
construction and development projects, as well as for unassigned turbines. It
includes previously delivered turbines, payments and delivery by year for the
remaining 5 turbines to be delivered as well as payment required for the
potential cancellation costs of the remaining 68 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 68 turbines.
-24-
Units to
Year Total Be Delivered
- -------------------------------------- ------------- ------------
(In thousands)
April through December 2004........... $ 76,497 5
2005.................................. 20,122 --
2006.................................. 2,623 --
----------- --
Total................................. $ 99,242 5
=========== ==
Litigation
The Company is party to various litigation matters arising out of the
normal course of business, the more significant of which are summarized below.
The ultimate outcome of each of these matters cannot presently be determined,
nor can the liability that could potentially result from a negative outcome be
reasonably estimated presently for every case. The liability the Company may
ultimately incur with respect to any one of these matters in the event of a
negative outcome may be in excess of amounts currently accrued with respect to
such matters and, as a result of these matters, may potentially be material to
the Company's Consolidated Condensed Financial Statements.
Securities Class Action Lawsuits. Since March 11, 2002, fourteen
shareholder lawsuits have been filed against Calpine and certain of its officers
in the United States District Court for the Northern District of California. The
actions captioned Weisz v. Calpine Corp., et al., filed March 11, 2002, and
Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are
purported class actions on behalf of purchasers of Calpine stock between March
15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18,
2002, is a purported class action on behalf of purchasers of Calpine stock
between February 6, 2001 and December 13, 2001. The eleven other actions,
captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v.
Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local
1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta
v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp., and Rose v.
Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The
complaints in these eleven actions are virtually identical-- they are filed by
three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of Calpine's
securities between January 5, 2001 and December 13, 2001.
The complaints in these fourteen actions allege that, during the purported
class periods, certain Calpine executives issued false and misleading statements
about Calpine's financial condition in violation of Sections 10(b) and 20(1) of
the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek
an unspecified amount of damages, in addition to other forms of relief.
In addition, a fifteenth securities class action, Ser v. Calpine, et al.,
was filed on May 13, 2002. The underlying allegations in the Ser action are
substantially the same as those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of Calpine's
8.5% Senior Notes Due February 15, 2011 ("2011 Notes") and the alleged class
period is October 15, 2001 through December 13, 2001. The Ser complaint alleges
that, in violation of Sections 11 and 15 of the Securities Act of 1933, the
Supplemental Prospectus for the 2011 Notes contained false and misleading
statements regarding Calpine's financial condition. This action names Calpine,
certain of its officers and directors, and the underwriters of the 2011 Notes
offering as defendants, and seeks an unspecified amount of damages, in addition
to other forms of relief.
All fifteen of these securities class action lawsuits were consolidated in
the United States District Court for the Northern District of California.
Plaintiffs filed a first amended complaint in October 2002. The amended
complaint did not include the 1933 Act complaints raised in the bondholders'
complaint, and the number of defendants named was reduced. On January 16, 2003,
before the Company's response was due to this amended complaint, plaintiffs
filed a further second complaint. This second amended complaint added three
additional Calpine executives and Arthur Andersen LLP as defendants. The second
amended complaint set forth additional alleged violations of Section 10 of the
Securities Exchange Act of 1934 relating to allegedly false and misleading
statements made regarding Calpine's role in the California energy crisis, the
long term power contracts with the California Department of Water Resources, and
Calpine's dealings with Enron, and additional claims under Section 11 and
Section 15 of the Securities Act of 1933 relating to statements regarding the
causes of the California energy crisis. The Company filed a motion to dismiss
this consolidated action in early April 2003.
On August 29, 2003, the judge issued an order dismissing, with leave to
amend, all of the allegations set forth in the second amended complaint except
for a claim under Section 11 of the Securities Act relating to statements
relating to the causes of the California energy crisis and the related increase
in wholesale prices contained in the Supplemental Prospectuses for the 2011
Notes.
-25-
The judge instructed plaintiff, Julies Ser, to file a third amended
complaint, which he did on October 17, 2003. The third amended complaint names
Calpine and three executives as defendants and alleges the Section 11 claim that
survived the judge's August 29, 2003 order.
On November 21, 2003, Calpine and the individual defendants moved to
dismiss the third amended complaint on the grounds that plaintiff's Section 11
claim was barred by the applicable one-year statute of limitations. On February
4, 2004, the judge denied the Company's motion to dismiss but has asked the
parties to be prepared to file summary judgment motions to address the statute
of limitations issue. The Company filed its answer to the third amended
complaint on February 28, 2004.
In a separate order dated February 4, 2004, the court denied without
prejudice Julies Ser's motion to be appointed lead plaintiff. Mr. Ser
subsequently stated he no longer desired to serve as lead plaintiff. On April 4,
2004, the Policemen and Firemen Retirement System of the City of Detroit ("P&F")
moved to be appointed lead plaintiff. The Company filed a response in opposition
to this motion. The court has scheduled a hearing on this matter for May 11,
2004.
The Company considers the lawsuit to be without merit and intends to
continue to defend vigorously against these allegations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities
class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was
filed on March 11, 2003, against Calpine, its directors and certain investment
banks in state superior court of San Diego County, California. The underlying
allegations in the Hawaii Structural Ironworkers Pension Fund action ("Hawaii
action") are substantially the same as the federal securities class actions
described above. However, the Hawaii action is brought on behalf of a purported
class of purchasers of Calpine's equity securities sold to public investors in
its April 2002 equity offering. The Hawaii action alleges that the Registration
Statement and Prospectus filed by Calpine which became effective on April 24,
2002, contained false and misleading statements regarding Calpine's financial
condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933.
The Hawaii action relies in part on Calpine's restatement of certain past
financial results, announced on March 3, 2003, to support its allegations. The
Hawaii action seeks an unspecified amount of damages, in addition to other forms
of relief.
The Company removed the Hawaii action to federal court in April 2003 and
filed a motion to transfer the case for consolidation with the other securities
class action lawsuits in the United States District Court for the Northern
District of California in May 2003. Plaintiff sought to have the action remanded
to state court, and on August 27, 2003, the United States District Court for the
Southern District of California granted plaintiff's motion to remand the action
to state court. In early October 2003 plaintiff agreed to dismiss the claims it
has against three of the outside directors.
On November 5, 2003, Calpine, the individual defendants and the underwriter
defendants filed motions to dismiss this complaint on numerous grounds. On
February 6, 2004, the court issued a tentative ruling sustaining the Company's
motion to dismiss on the issue of plaintiff's standing. The court found that
plaintiff had not shown that it had purchased Calpine stock "traceable" to the
April 2002 equity offering. The court overruled the Company's motion to dismiss
on all other grounds. On March 12, 2004, after oral argument on the issues, the
court confirmed its February 2, 2004, ruling.
On February 20, 2004, plaintiff filed an amended complaint, and in late
March 2004 the Company and the individual defendants filed answers to this
complaint. On April 9, 2004, the Company and the individual defendants filed
motions to transfer the lawsuit to Santa Clara County Superior Court, which
motions were granted on May 7, 2004. The Company considers this lawsuit to be
without merit and intends to continue to defend vigorously against it.
Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in
the Calpine Corporation Retirement Savings Plan (the "401(k) Plan") filed a
class action lawsuit in the United States District Court for the Northern
District of California. The underlying allegations in this action ("Phelps
action") are substantially the same as those in the securities class actions
described above. However, the Phelps action is brought on behalf of a purported
class of participants in the 401(k) Plan. The Phelps action alleges that various
filings and statements made by Calpine during the class period were materially
false and misleading, and that defendants failed to fulfill their fiduciary
obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to
invest in Calpine common stock. The Phelps action seeks an unspecified amount of
damages, in addition to other forms of relief. In May 2003 Lennette Poor-Herena,
another participant in the 401(k) Plan, filed a substantially similar class
action lawsuit as the Phelps action also in the Northern District of California.
Plaintiffs' counsel is the same in both of these actions, and they have agreed
to consolidate these two cases and to coordinate them with the consolidated
federal securities class actions described above. On January 20, 2004, plaintiff
James Phelps filed a consolidated ERISA complaint naming Calpine and numerous
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individual current and former Calpine Board members and employees as defendants.
Pursuant to a stipulated agreement with plaintiff, Calpine's response to the
amended complaint is due June 18, 2004. The Company considers this lawsuit to be
without merit and intends to vigorously defend against it.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of Calpine against its directors and one of
its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. and
is pending in state superior court of Santa Clara County, California. Calpine is
a nominal defendant in this lawsuit, which alleges claims relating to
purportedly misleading statements about Calpine and stock sales by certain of
the director defendants and the officer defendant. In December 2002 the court
dismissed the complaint with respect to certain of the director defendants for
lack of personal jurisdiction, though plaintiff may appeal this ruling. In early
February 2003 plaintiff filed an amended complaint. In March 2003 Calpine and
the individual defendants filed motions to dismiss and motions to stay this
proceeding in favor of the federal securities class actions described above. In
July 2003 the court granted the motions to stay this proceeding in favor of the
consolidated federal securities class actions described above. The Company
cannot estimate the possible loss or range of loss from this matter. The Company
considers this lawsuit to be without merit and intends to vigorously defend
against it.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District of
California on behalf of Calpine against its directors, captioned Gordon v.
Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003 plaintiff agreed to stay these proceedings in
favor of the consolidated federal securities class action described above and to
dismiss without prejudice certain director defendants. On March 4, 2003,
plaintiff filed papers with the court voluntarily agreeing to dismiss without
prejudice the claims he had against three of the outside directors. The Company
cannot estimate the possible loss or range of loss from this matter. The Company
considers this lawsuit to be without merit and intends to continue to defend
vigorously against it.
Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, Calpine
sued Automated Credit Exchange ("ACE") in state superior court of Alameda
County, California for negligence and breach of contract to recover reclaim
trading credits, a form of emission reduction credits that should have been held
in Calpine's account with U.S. Trust Company ("US Trust"). Calpine wrote off
$17.7 million in December 2001 related to losses that it alleged were caused by
ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002,
pursuant to which ACE made a payment to Calpine of $7 million and transferred to
Calpine the rights to the emission reduction credits to be held by ACE. The
Company recognized the $7 million as income in the second quarter of 2002. In
June 2002 a complaint was filed by InterGen North America, L.P. ("InterGen")
against Anne M. Sholtz, the owner of ACE, and EonXchange, another
Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002.
InterGen alleges it suffered a loss of emission reduction credits from
EonXchange in a manner similar to Calpine's loss from ACE. InterGen's complaint
alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other
Sholtz entities and that ACE and other Sholtz entities should be deemed to be
one economic enterprise and all retroactively included in the EonXchange
bankruptcy filing as of May 6, 2002. By a judgment entered on October 30, 2002,
the bankruptcy court consolidated ACE and the other Sholtz controlled entities
with the bankruptcy estate of EonXchange. Subsequently, the Trustee of
EonXchange filed a separate motion to substantively consolidate Anne Sholtz into
the bankruptcy estate of EonXchange. Although Anne Sholtz initially opposed such
motion, she entered into a settlement agreement with the Trustee consenting to
her being substantively consolidated into the bankruptcy proceeding. The
bankruptcy court entered an order approving Anne Sholtz's settlement agreement
with the Trustee on April 3, 2002. On July 10, 2003, Howard Grobstein, the
Trustee in the EonXchange bankruptcy, filed a complaint for avoidance against
Calpine, seeking recovery of the $7 million (plus interest and costs) paid to
Calpine in the March 29, 2002 Settlement Agreement. The complaint claims that
the $7 million received by Calpine in the Settlement Agreement was transferred
within 90 days of the filing of bankruptcy and therefore should be avoided and
preserved for the benefit of the bankruptcy estate. On August 28, 2003, Calpine
filed its answer denying that the $7 million is an avoidable preference. On
January 26, 2004, Calpine filed a motion for partial summary judgment asserting
that the bankruptcy court did not properly consolidate Anne Sholtz into the
bankruptcy estate of EonXchange. If the motion is granted, at least $2.9 million
of the $7 million that the Trustee is seeking to recover from Calpine could not
be avoided as a preferential transfer. In response, the Trustee filed a motion
for summary judgment for the entire $7 million plus interest against Calpine.
Although Calpine will assert various defenses to the claims asserted by the
Trustee, Calpine and the Trustee have entered into stipulations to continue the
various hearing dates on the pending motions for summary judgment in order to
pursue settlement discussions. The Company believes that it has adequately
reserved for the possible loss, if any, that it may ultimately incur as a result
of this matter.
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International Paper Company v. Androscoggin Energy LLC. In October 2000
International Paper Company ("IP") filed a complaint in the United States
District Court for the Northern District of Illinois against Androscoggin Energy
LLC ("AELLC") alleging that AELLC breached certain contractual representations
and warranties by failing to disclose facts surrounding the termination,
effective May 8, 1998, of one of AELLC's fixed-cost gas supply agreements. The
Company acquired a 32.3% interest in AELLC as part of the SkyGen transaction
which closed in October 2000. AELLC filed a counterclaim against IP that has
been referred to arbitration that AELLC may commence at its discretion upon
further evaluation. On November 7, 2002, the court issued an opinion on the
parties' cross motions for summary judgment finding in AELLC's favor on certain
matters though granting summary judgment to IP on the liability aspect of a
particular claim against AELLC. The court also denied a motion submitted by IP
for preliminary injunction to permit IP to make payment of funds into escrow
(not directly to AELLC) and require AELLC to post a significant bond.
In mid-April of 2003 IP unilaterally availed itself to self-help in
withholding amounts in excess of $2.0 million as a set-off for litigation
expenses and fees incurred to date as well as an estimated portion of a rate
fund to AELLC. Upon AELLC's amended complaint and request for immediate
injunctive relief against such actions, the court ordered that IP must pay the
approximately $1.2 million withheld as attorneys' fees related to the litigation
as any such perceived entitlement was premature, but deferred to provide
injunctive relief on the incomplete record concerning the offset of $799,000 as
an estimated pass-through of the rate fund. IP complied with the order on April
29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On
June 26, 2003, the court entered an order dismissing AELLC's amended
counterclaim without prejudice to AELLC refiling the claims as breach of
contract claims in a separate lawsuit. On December 11, 2003, the court denied in
part IP's summary judgment motion pertaining to damages. In short, the court:
(i) determined that, as a matter of law, IP is entitled to pursue an action for
damages as a result of AELLC's breach, and (ii) ruled that sufficient questions
of fact remain to deny IP summary judgment on the measure of damages as IP did
not sufficiently establish causation resulting from AELLC's breach of contract
(the liability aspect of which IP obtained a summary judgment in December 2002).
On February 2, 2004, the parties filed a Final Pretrial Order with the court.
The case appears likely scheduled for trial in the second quarter of 2004,
subject to the court's discretion and calendar. The Company believes that it has
adequately reserved for the possible loss, if any, that it may ultimately incur
as a result of this matter.
Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22,
2003, Pacific Gas and Electric Company ("PG&E") filed with the California Public
Utilities Commission ("CPUC") a Complaint of PG&E and Request for Immediate
Issuance of an Order to Show Cause ("complaint") against Calpine Corporation,
CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas
Company, and Lodi Gas Storage, LLC ("LGS"). The complaint requests the CPUC to
issue an order requiring defendants to show cause why they should not be ordered
to cease and desist from using any direct interconnections between the
facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek
and obtain regulatory approval from the CPUC. The complaint also seeks an order
directing defendants to pay to PG&E any underpayments of PG&E's tariffed
transportation rates and to make restitution for any profits earned from any
business activity related to LGS' direct interconnections to any entity other
than PG&E. The complaint further alleges that various natural gas consumers,
including Calpine affiliated generation projects within California, are engaged
with defendants in the acts complained of, and that the defendants unlawfully
bypass PG&E's system and operate as an unregulated local distribution company
within PG&E's service territory. On August 27, 2003, Calpine filed its answer
and a motion to dismiss. LGS also made similar filings. On October 16, 2003, the
presiding administrative law judge denied the motion to dismiss and on October
24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule
and set the matter for an evidentiary hearing. On January 15, 2004, Calpine, LGS
and PG&E executed a Settlement Agreement to resolve all outstanding allegations
and claims raised in the complaint. Certain aspects of the Settlement Agreement
are effective immediately and the effectiveness of other provisions is subject
to the approval of the Settlement Agreement by the CPUC. In the event the CPUC
fails to approve the Settlement Agreement, its operative terms and conditions
become null and void. The Settlement Agreement provides, in part, for: 1) PG&E
to be paid $2.7 million; 2) the disconnection of the LGS interconnections with
Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental
approval before resuming any sales or exchanges at the Ryer Island Meter
Station; 4) PG&E's withdrawal of its public utility claims against Calpine; and
5) no party admitting any wrongdoing. Accordingly, the presiding administrative
law judge vacated the hearing schedule and established a new procedural schedule
for the filing of the Settlement Agreement. On February 6, 2004, the Settlement
Agreement was filed with the CPUC. The parties were given the opportunity to
submit comments and reply comments on the Settlement Agreement. The matter is
currently pending and shall be considered by the CPUC following the issuance of
a recommendation by the presiding administrative law judge.
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
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certain of its affiliates in the United States District Court for the Northern
District of Texas, alleging, among other things, that the Company breached
duties of care and loyalty allegedly owed to Panda by failing to correctly
construct and operate the Oneta Energy Center ("Oneta"), which the Company
acquired from Panda, in accordance with Panda's original plans. Panda alleges
that it is entitled to a portion of the profits from Oneta plant and that
Calpine's actions have reduced the profits from Oneta plant thereby undermining
Panda's ability to repay monies owed to Calpine on December 1, 2003, under a
promissory note on which approximately $38.6 million (including interest) is
currently outstanding and past due. The note is collateralized by Panda's
carried interest in the income generated from Oneta, which achieved full
commercial operations in June 2003. The company filed a counterclaim against
Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty, and have
also filed a motion to dismiss as to the causes of action alleging federal and
state securities laws violations. The motion to dismiss is currently pending
before the court. However, at the present time, the Company cannot estimate the
potential loss, if any, that might arise from this matter. The Company considers
Panda's lawsuit to be without merit and intends to defend vigorously against it.
The Company stopped accruing interest income on the promissory note due December
1, 2003, as of the due date because of Panda's default in repayment of the note.
California Business & Professions Code Section 17200 Cases, of which the
lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C.,
et al. This purported class action complaint filed in May 2002 against twenty
energy traders and energy companies, including CES, alleges that defendants
exercised market power and manipulated prices in violation of California
Business & Professions Code Section 17200 et seq., and seeks injunctive relief,
restitution, and attorneys' fees. The Company also have been named in seven
other similar complaints for violations of Section 17200. All seven cases were
removed from the various state courts in which they were originally filed to
federal court for pretrial proceedings with other cases in which the Company is
not named as a defendant. However, at the present time, the Company cannot
estimate the potential loss, if any, that might arise from this matter. The
Company considers the allegations to be without merit, and filed a motion to
dismiss on August 28, 2003. The court granted the motion, and plaintiffs have
appealed.
Prior to the motion to dismiss being granted, one of the actions, captioned
Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to state
superior court of Alameda County, California. On January 12, 2004, CES was added
as a defendant in Millar. This action includes similar allegations to the other
17200 cases, but also seeks rescission of the long-term power contracts with the
California Department of Water Resources.
Upon motion from another newly added defendant, Millar was recently removed
to federal court. It has now been transferred to the same judge that is
presiding over the other 17200 cases described above, where it will be
consolidated with such cases for pretrial purposes. The Company anticipates
filing a timely motion for dismissal of Millar as well.
Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy
Services, L.P. before the FERC, filed on December 4, 2001. Nevada Section 206
Complaint. On December 4, 2001, Nevada Power Company ("NPC") and Sierra Pacific
Power Company ("SPPC") filed a complaint with FERC under Section 206 of the
Federal Power Act against a number of parties to their power sales agreements,
including Calpine. NPC and SPPC allege in their complaint, which seeks a refund,
that the prices they agreed to pay in certain of the power sales agreements,
including those signed with Calpine, were negotiated during a time when the
power market was dysfunctional and that they are unjust and unreasonable. The
administrative law judge issued an Initial Decision on December 19, 2002, that
found for Calpine and the other respondents in the case and denied NPC the
relief that it was seeking. In June 2003, FERC rejected the complaint. Some
plaintiffs appealed to the FERC and their request for rehearing was denied. The
FERC decision is therefore final, and the matter is pending on appeal before the
United States Court of Appeals for the Ninth Circuit.
Transmission Service Agreement with Nevada Power. On March 16, 2004, NPC
filed a petition for declaratory order at FERC (Docket No. EL04-90-000) asking
that an order be issued requiring Calpine and Reliant Energy Services, Inc. to
pay for transmission service under their Transmission Service Agreements
("TSAs") with NPC or, if the TSAs are terminated, to pay the lesser of the
transmission charges or a pro rata share of the total cost of NPC's Centennial
Project (approximately $33 million for Calpine). Calpine had previously provided
security to NPC for these costs in the form of a surety bond issued by Fireman's
Fund Insurance Company ("FFIC"). The Centennial Project involves construction of
various transmission facilities in two phases; Calpine's Moapa Energy Center
("MEC") is scheduled to receive service under its TSA from facilities yet to be
constructed in the second phase of the Centennial Project. Calpine has filed a
protest to the petition asserting that Calpine will take service under the TSA
if NPC proceeds to execute a purchase power agreement ("PPA") with MEC based on
its winning bid in the Request for Proposals that NPC conducted in 2003. Calpine
also has taken the position that if NPC does not execute a PPA with MEC, it will
terminate the TSA and any payment by Calpine would be limited to a pro rata
allocation of costs incurred to date on the second phase of the project
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(approximately $4.5 million in total) among the three customers to be served. At
this time, Calpine is unable to predict the final outcome of this proceeding or
its impact on Calpine.
On or about April 27, 2004, NPC alleged to FFIC that Calpine had defaulted
on the TSA and made demand on FFIC for the full amount of the surety bond,
$33,333,333.00. On April 29, 2004, FFIC filed a complaint for declaratory order
in state superior court of Marin County, California in connection with this
demand.
FFIC's complaint asks that an order be issued declaring that it has no
obligation to make payment under the bond and, if the court determines that FFIC
does have an obligation to make payment, FFIC asks that an order be issued
declaring that (i) Calpine has an obligation to replace it with funds equal to
the amount of NPC's demand against the bond and (ii) Calpine is obligated to
indemnify and hold FFIC harmless for all loss, costs and fees incurred as a
result of the issuance of the bond. Calpine is preparing to file a response to
the complaint. Calpine's position will be, among other items, that it did not
default on its obligations under the TSA and therefore NPC is not entitled to
make a demand upon the FFIC bond. At this time, Calpine is unable to predict the
outcome of this proceeding or its impact on Calpine.
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002, Calpine Canada Natural Gas Partnership ("Calpine Canada") filed a
complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp.
("Enron Canada") owed it approximately $1.5 million from the sale of gas in
connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron
Canada has not sought bankruptcy relief and has counterclaimed in the amount of
$18 million. Discovery is currently in progress, and the Company believes that
Enron Canada's counterclaim is without merit and intends to vigorously defend
against it.
Jones v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones
and the Estate of Cynthia Jones filed a complaint against Calpine in the United
States District Court for the Western District of Washington. Calpine purchased
Goldendale Energy, Inc., a Washington corporation, from Darrell Jones. The
agreement provided, among other things, that upon substantial completion of the
Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0
million less $0.2 million per day for each day that elapsed between July 1,
2002, and the date of substantial completion. Substantial completion of the
Goldendale facility has not occurred and the daily reduction in the payment
amount has reduced the $18.0 million payment to zero. The complaint alleges that
by not achieving substantial completion by July 1, 2002, Calpine breached its
contract with Mr. Jones, violated a duty of good faith and fair dealing, and
caused an inequitable forfeiture. The complaint seeks damages in an unspecified
amount in excess of $75,000. On July 28, 2003, Calpine filed a motion to dismiss
the complaint for failure to state a claim upon which relief can be granted. The
court granted Calpine's motion to dismiss the complaint on March 10, 2004.
Plaintiffs have filed a motion for reconsideration of the decision, and the
plaintiffs may also ultimately appeal. The Company still, however, expects to
make the $6.0 million payment to the estates when the project is completed.
In addition, the Company is involved in various other claims and legal
actions arising out of the normal course of its business. The Company does not
expect that the outcome of these proceedings will have a material adverse effect
on its financial position or results of operations.
13. Operating Segments
The Company is first and foremost an electric generating company. In
pursuing this single business strategy, it is the Company's long-range objective
to produce from its own natural gas reserves ("equity gas") at a level of
approximately 25% of its fuel consumption requirements. The Company's oil and
gas production and marketing activity has reached the quantitative criteria to
be considered a reportable segment under SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." The Company's segments are
electric generation and marketing; oil and gas production and marketing; and
corporate and other activities. Electric generation and marketing includes the
development, acquisition, ownership and operation of power production
facilities, hedging, balancing, optimization, and trading activity transacted on
behalf of the Company's power generation facilities. Oil and gas production
includes the ownership and operation of gas fields, gathering systems and gas
pipelines for internal gas consumption, third party sales and hedging,
balancing, optimization, and trading activity transacted on behalf of the
Company's oil and gas operations. Corporate activities and other consists
primarily of financing activities, the Company's specialty data center
engineering business, which was divested in the third quarter of 2003 and
general and administrative costs. Certain costs related to company-wide
functions are allocated to each segment, such as interest expense, distributions
on HIGH TIDES prior to October 1, 2003, and interest income, which are allocated
based on a ratio of segment assets to total assets.
The Company evaluates performance based upon several criteria including
profits before tax. The financial results for the Company's operating segments
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have been prepared on a basis consistent with the manner in which the Company's
management internally disaggregates financial information for the purposes of
assisting in making internal operating decisions.
Due to the integrated nature of the business segments, estimates and
judgments have been made in allocating certain revenue and expense items, and
reclassifications have been made to prior periods to present the allocation
consistently.
Electric Oil and Gas
Generation Production
and Marketing and Marketing Corporate and Other Total
----------------------- ------------------ ------------------- -----------------------
2004 2003 2004 2003 2004 2003 2004 2003
---------- ---------- -------- -------- -------- -------- ---------- ----------
(In thousands)
For the three months ended March 31,
Total revenue from external
customers..................... $1,998,393 $2,138,498 $ 24,381 $ 24,892 $ 19,964 $ 2,543 $2,042,738 $2,165,933
Intersegment revenue............ -- -- 80,110 125,214 -- -- 80,110 125,214
Segment profit/(loss) before
provision for income taxes.... (243,873) (72,391) 19,500 47,394 44,375 (43,413) (179,998) (68,410)
Equipment cancellation and
impairment cost............... 2,360 87 -- -- -- -- 2,360 87
Electric Oil and Gas Corporate,
Generation Production Other and
and Marketing and Marketing Eliminations Total
------------- ------------- ------------ ------------
(In thousands)
Total assets:
March 31, 2004................... $ 24,754,356 $ 1,667,578 $ 940,104 $ 27,362,038
December 31, 2003................ $ 24,067,448 $ 1,797,755 $ 1,438,729 $ 27,303,932
Intersegment revenues primarily relate to the use of internally procured
gas for the Company's power plants. These intersegment revenues have been
included in Total Revenue and Income before taxes in the oil and gas production
and marketing reporting segment and eliminated in the Corporate and other
reporting segment.
14. California Power Market
California Refund Proceeding. On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric
Company under Section 206 of the Federal Power Act alleging, among other things,
that the markets operated by the California Independent System Operator
("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. In
addition to commencing an inquiry regarding the market structure, FERC
established a refund effective period of October 2, 2000, to June 19, 2001, for
sales made into those markets.
On December 12, 2002, the Administrative Law Judge ("ALJ") issued a
Certification of Proposed Finding on California Refund Liability ("December 12
Certification") making an initial determination of refund liability. On March
26, 2003, FERC also issued an order adopting many of the ALJ's findings set
forth in the December 12 Certification (the "March 26 Order"). In addition, as a
result of certain findings by the FERC staff concerning the unreliability or
misreporting of certain reported indices for gas prices in California during the
refund period, FERC ordered that the basis for calculating a party's potential
refund liability be modified by substituting a gas proxy price based upon gas
prices in the producing areas plus the tariff transportation rate for the
California gas price indices previously adopted in the refund proceeding. The
Company believes, based on the available information, that any refund liability
that may be attributable to it will increase modestly, from approximately $6.2
million to $8.4 million, after taking the appropriate set-offs for outstanding
receivables owed by the CalPX and CAISO to Calpine. The Company has fully
reserved the amount of refund liability that by its analysis would potentially
be owed under the refund calculation clarification in the March 26 order. The
final determination of the refund liability is subject to further Commission
proceedings to ascertain the allocation of payment obligations among the
numerous buyers and sellers in the California markets. At this time, the Company
is unable to predict the timing of the completion of these proceedings or the
final refund liability. Thus the impact on the Company's business is uncertain
at this time.
On April 26, 2004, Dynegy Inc. entered into a settlement of the California
Refund Proceeding and other proceedings with California governmental entities
and the three California investor-owned utilities. The California governmental
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entities include the Attorney General, the California Public Utilities
Commission, the California Department of Water Resources ("CDWR"), and the
California Electricity Oversight Board. Also, on April 27, 2004, The Williams
Companies, Inc. ("Williams") entered into a settlement of the California Refund
Proceeding and other proceedings with the three California investor-owned
utilities; previously, Williams had entered into a settlement of the same
matters with the California governmental entities. The Williams settlement with
the California governmental entities was similar to the settlement that Calpine
entered into with the California governmental entities on April 22, 2002.
Calpine's settlement was approved by FERC on March 26, 2004, in an order which
partially dismissed Calpine from the California Refund Proceeding to the extent
that any refunds are owed for power sold by Calpine to CDWR or any other agency
of the State of California.
FERC Investigation into Western Markets. On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western United States. This investigation was initiated as a
result of allegations that Enron and others used their market position to
distort electric and natural gas markets in the West. The scope of the
investigation is to consider whether, as a result of any manipulation in the
short-term markets for electric energy or natural gas or other undue influence
on the wholesale markets by any party since January 1, 2000, the rates of the
long-term contracts subsequently entered into in the West are potentially unjust
and unreasonable. FERC has stated that it may use the information gathered in
connection with the investigation to determine how to proceed on any existing or
future complaint brought under Section 206 of the Federal Power Act involving
long-term power contracts entered into in the West since January 1, 2000, or to
initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding
on its own initiative. On August 13, 2002, the FERC staff issued the Initial
Report on Company-Specific Separate Proceedings and Generic Reevaluations;
Published Natural Gas Price Data; and Enron Trading Strategies (the "Initial
Report") summarizing its initial findings in this investigation. There were no
findings or allegations of wrongdoing by Calpine set forth or described in the
Initial Report. On March 26, 2003, the FERC staff issued a final report in this
investigation (the "Final Report"). The FERC staff recommended that FERC issue a
show cause order to a number of companies, including Calpine, regarding certain
power scheduling practices that may have been be in violation of the CAISO's or
CalPX's tariff. The Final Report also recommended that FERC modify the basis for
determining potential liability in the California Refund Proceeding discussed
above. Calpine believes that it did not violate these tariffs and that, to the
extent that such a finding could be made, any potential liability would not be
material.
Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject Calpine to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per megawatt hour into markets operated by either the
CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may
have violated CAISO and CalPX tariff prohibitions. No individual market
participant was identified. The Company believes that it did not violate the
CAISO and CalPX tariff prohibitions referred to by FERC in this order; however,
the Company is unable to predict at this time the final outcome of this
proceeding or its impact on Calpine.
CPUC Proceeding Regarding QF Contract Pricing for Past Periods. The
Company's Qualifying Facilities ("QF") contracts with PG&E provide that the CPUC
has the authority to determine the appropriate utility "avoided cost" to be used
to set energy payments for certain QF contracts by determining the short run
avoided cost ("SRAC") energy price formula. In mid-2000 the Company's QF
facilities elected the option set forth in Section 390 of the California Public
Utility Code, which provides QFs the right to elect to receive energy payments
based on the CalPX market clearing price instead of the price determined by
SRAC. Having elected such option, the Company was paid based upon the PX zonal
day-ahead clearing price ("PX Price") from summer 2000 until January 19, 2001,
when the PX ceased operating a day-ahead market. The CPUC has conducted
proceedings (R.99-11-022) to determine whether the PX Price was the appropriate
price for the energy component upon which to base payments to QFs which had
elected the PX-based pricing option. The CPUC at one point issued a proposed
decision to the effect that the PX Price was the appropriate price for energy
payments under the California Public Utility Code but tabled it, and a final
decision has not been issued to date. Therefore, it is possible that the CPUC
could order a payment adjustment based on a different energy price
determination. On April 29, 2004, PG&E, The Utility Reform Network, which is a
consumer advocacy group, and the Office of Ratepayer Advocates, which is an
independent consumer advocacy department of the CPUC, (collectively, the "PG&E
Parties") filed a Motion for Briefing Schedule Regarding True-Up of Payments to
QF Switchers (the "April 29 Motion"). The April 29 Motion requests that the CPUC
set a briefing schedule under the R.99-11-022 to determine refund liability of
the QFs who had switched to the PX Price during the period of June 1, 2000,
until January 19, 2001. The PG&E Parties allege that refund liability be
determined using the methodology that has been developed thus far in the
California Refund Proceeding discussed above. The Company believes that the PX
-32-
Price was the appropriate price for energy payments and that the basis for any
refund liability based on the interim determination by FERC in the California
Refund Proceeding is unfounded, but there can be no assurance that this will be
the outcome of the CPUC proceedings.
Geysers Reliability Must Run Section 206 Proceeding. CAISO, California
Electricity Oversight Board, Public Utilities Commission of the State of
California, Pacific Gas and Electric Company, San Diego Gas & Electric Company,
and Southern California Edison (collectively referred to as the "Buyers
Coalition") filed a complaint on November 2, 2001 at the FERC requesting the
commencement of a Federal Power Act Section 206 proceeding to challenge one
component of a number of separate settlements previously reached on the terms
and conditions of "reliability must run" contracts ("RMR Contracts") with
certain generation owners, including Geysers Power Company, LLC, which
settlements were also previously approved by the FERC. RMR Contracts require the
owner of the specific generation unit to provide energy and ancillary services
when called upon to do so by the ISO to meet local transmission reliability
needs or to manage transmission constraints. The Buyers Coalition has asked FERC
to find that the availability payments under these RMR Contracts are not just
and reasonable. Geysers Power Company, LLC filed an answer to the complaint in
November 2001. To date, FERC has not established a Section 206 proceeding. The
outcome of this litigation and the impact on the Company's business cannot be
determined at the present time.
15. Subsequent Events
On April 15, 2004, the Company agreed to modify the terms of its long-term
operating lease for the 120-megawatt King City Power Plant located in King City,
California. Upon closing of this transaction, the Company expects to: (1) extend
the term of the King City Power Plant's operating lease from 2018 to 2028; (2)
restructure the lease's rent payment schedule; (3) receive approximately $87
million in cash, net of transaction costs from the sale of securities originally
pledged to the lessor to secure the lessee's obligations under the lease; (4)
receive approximately $40 million through the issuance of a 10-year promissory
note by Calpine Canada Power Ltd., to a CPIF affiliate; and (5) redeem the
existing preferred equity interest issued in 2003 by a Company subsidiary in
connection with the King City Power Plant. Together, these transactions will
result in a reduction of approximately $42 million of the Company's debt and are
expected to provide the Company with approximately $45 million in net cash
proceeds. The closing is contingent upon the completion of the CPIF Subscription
Receipt Offering which is expected to close on May 19, 2004. The Company expects
to record a gain from this transaction.
On April 26, 2004, the Company successfully completed its consent
solicitation to effect certain amendments to the Indentures governing certain of
Calpine's public debt securities. The purpose of the amendments is to conform
certain of the covenants in these Indentures to comparable provisions in the
Indentures and other financing instruments governing the non-convertible debt
issued by Calpine in 2003. The amended Indentures govern the Senior Notes issued
by Calpine between 1996 and 1999, and are as follows:
o 10 1/2% Senior Notes due 2006
o 8 3/4% Senior Notes due 2007
o 7 7/8% Senior Notes due 2008
o 7 5/8% Senior Notes due 2006
o 7 3/4% Senior Notes due 2009
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)
-33-
uncertainties associated with cost estimates, that actual costs may be higher
than estimated, (viii) development of lower-cost power plants or of a lower cost
means of operating a fleet of power plants by our competitors, (ix) risks
associated with marketing and selling power from power plants in the evolving
energy market, (x) factors that impact exploitation of oil or gas resources,
such as the geology of a resource, the total amount and costs to develop
recoverable reserves, and legal title, regulatory, gas administration, marketing
and operational factors relating to the extraction of natural gas, (xi)
uncertainties associated with estimates of oil and gas reserves, (xii) the
effects on our business resulting from reduced liquidity in the trading and
power generation industry, (xiii) our ability to access the capital markets on
attractive terms or at all, (xiv) uncertainties associated with estimates of
sources and uses of cash, that actual sources may be lower and actual uses may
be higher than estimated, (xv) the direct or indirect effects on our business of
a lowering of our credit rating (or actions we may take in response to changing
credit rating criteria), including increased collateral requirements, refusal by
our current or potential counterparties to enter into transactions with us and
our inability to obtain credit or capital in desired amounts or on favorable
terms, (xvi) present and possible future claims, litigation and enforcement
actions, (xvii) effects of the application of regulations, including changes in
regulations or the interpretation thereof, and (xviii) other risks identified in
this report. You should also carefully review the risks described in other
reports that we file with the Securities and Exchange Commission, including
without limitation our annual report on Form 10-K for the year ended December
31, 2003. 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.
-34-
Three Months Ended
March 31,
-----------------------------
2004 2003
-------------- -------------
(In thousands, except
production and pricing data)
Power Plants:
Electricity and steam ("E&S") revenues:
Energy........................................................... $ 933,369 $ 814,810
Capacity......................................................... 180,593 157,443
Thermal and other................................................ 131,925 131,282
-------------- -------------
Subtotal......................................................... $ 1,245,887 $ 1,103,535
Spread on sales of purchased power(1)............................... 5,089 1,335
-------------- -------------
Adjusted E&S revenues (non-GAAP).................................... $ 1,250,976 $ 1,104,870
Megawatt hours produced............................................. 21,050,000 19,100,000
All-in electricity price per megawatt hour generated................ $ 59.43 $ 57.85
- ----------
<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, 2004 and 2003, that
represent purchased power and purchased gas sales for hedging and optimization
and the costs we incurred to purchase the power and gas that we resold during
these periods (in thousands, except percentage data):
Three Months Ended
March 31,
-----------------------------
2004 2003
------------- -------------
Total revenue....................................................... $ 2,042,738 $ 2,165,933
Sales of purchased power for hedging and optimization (1)........... 380,028 681,284
As a percentage of total revenue.................................... 18.6% 31.5%
Sale of purchased gas for hedging and optimization.................. 352,737 327,468
As a percentage of total revenue.................................... 17.3% 15.1%
Total cost of revenue ("COR")....................................... 1,922,194 2,000,796
Purchased power expense for hedging and optimization (1)............ 374,939 679,949
As a percentage of total COR........................................ 19.5% 34.0%
Purchased gas expense for hedging and optimization.................. 360,486 316,948
As a percentage of total COR........................................ 18.8% 15.8%
- ----------
<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 Financial
Statements for a discussion of our application of EITF Issue No. 03-11.
</FN>
The primary reasons for the significant levels of these sales and costs of
revenue items include: (a) significant levels of hedging, balancing and
optimization activities by our Calpine Energy Services, L.P. ("CES") risk
management organization; (b) particularly volatile markets for electricity and
natural gas, which prompted us to frequently adjust our hedge positions by
buying power and gas and reselling it; (c) the accounting requirements under
Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial
Statements," and EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Asset", under which we show many of our hedging contracts on a
gross basis (as opposed to netting sales and cost of revenue); and (d) rules in
effect throughout 2001 and 2002 associated with the NEPOOL market in New
England, which require that all power generated in NEPOOL be sold directly to
the Independent System Operator ("ISO") in that market; we then buy from the ISO
to serve our customer contracts. Generally accepted accounting principles
required us to account for this activity, which applies to three of our merchant
generating facilities, as the aggregate of two distinct sales and one purchase
until our prospective adoption of EITF Issue No. 03-11 on October 1, 2003. This
gross basis presentation increases revenues but not gross profit. The table
below details the financial extent of our transactions with NEPOOL for all
-35-
financial periods prior to the adoption of EITF Issue No. 03-11. Our entrance
into the NEPOOL market began with our acquisition of the Dighton, Tiverton and
Rumford facilities on December 15, 2000.
Three Months Ended
March 31,2003
------------------
(In thousands)
Sales to NEPOOL from power we generated................. $ 76,898
Sales to NEPOOL from hedging and other activity......... 83,011
-----------
Total sales to NEPOOL................................ $ 159,909
Total purchases from NEPOOL.......................... $ 134,168
Overview
Our core business and primary source of revenue is the generation and
delivery of electric power. We provide power to our U.S., Canadian and U.K.
customers through the development and construction or acquisition, and operation
of efficient and environmentally friendly electric power plants fueled primarily
by natural gas and, to a much lesser degree, by geothermal resources. We own and
produce natural gas and to a lesser extent oil, which we use primarily to lower
our costs of power production and provide a natural hedge of fuel costs for our
electric power plants, but also to generate some revenue through sales to third
parties. We protect and enhance the value of our electric and gas assets with a
sophisticated risk management organization. We also protect our power generation
assets and control certain of our costs by producing certain of the combustion
turbine replacement parts that we use at our power plants, and we generate
revenue by providing combustion turbine parts to third parties. Finally, we
offer services to third parties to capture value in the skills we have honed in
building, commissioning and operating power plants.
Our key opportunities and challenges include:
o preserving and enhancing our liquidity while spark spreads (the
differential between power revenues and fuel costs) are depressed,
o selectively adding new load-serving entities and power users to our
satisfied customer list as we increase our power contract portfolio,
and
o continuing to add value through prudent risk management and
optimization activities.
Since the latter half of 2001, there has been a significant contraction in
the availability of capital for participants in the energy sector. This has been
due to a range of factors, including uncertainty arising from the collapse of
Enron Corp. and a perceived near-term surplus supply of electric generating
capacity. These factors have continued through 2003 and into 2004, during which
decreased spark spreads have adversely impacted our liquidity and earnings.
While we have been able to continue to access the capital and bank credit
markets on attractive terms, we recognize that the terms of financing available
to us in the future may not be attractive. To protect against this possibility
and due to current market conditions, we scaled back our capital expenditure
program to enable us to conserve our available capital resources. We have
recently completed the refinancing of Calpine Generating Company ("CalGen"),
formerly Calpine Construction Finance Company II, LLC ("CCFC II") revolving
construction facility indebtedness of approximately $2.3 billion as further
discussed in Note 6 of the Notes to Consolidated Condensed Financial Statements.
Set forth below are the Results of Operations for the three months ended
March 31, 2004 and 2003.
Results of Operations
Three Months Ended March 31, 2004, Compared to Three Months Ended March 31, 2003
(in millions, except for unit pricing information, percentages and MW volumes).
Revenue
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Total revenue....................................................... $ 2,042.7 $ 2,165.9 $ (123.2) (5.7)%
-36-
The change in total revenue is explained by category below.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Electricity and steam revenue....................................... $ 1,245.9 $ 1,103.5 $ 142.4 12.9%
Sales of purchased power for hedging and optimization............... 380.0 681.3 (301.3) (44.2)%
----------- ----------- -----------
Total electric generation and marketing revenue.................. $ 1,625.9 $ 1,784.8 $ (158.9) (8.9)%
=========== =========== ===========
Electricity and steam revenue increased as we completed construction and
brought into operation 5 new baseload power plants, 2 new peaker facilities and
4 expansion projects completed subsequent to March 31, 2003. Average megawatts
in operation of our consolidated plants increased by 21% to 21,852 MW while
generation increased by 10%. The increase in generation lagged behind the
increase in average MW in operation as our baseload capacity factor dropped to
50.3% in the three months ended March 31, 2004 from 55.2% in the three months
ended March 31, 2003 primarily due to the increased occurrence of unattractive
off-peak market spark spreads in certain areas reflecting mild weather in the
first quarter of 2004. Average realized electric price, before the effects of
hedging, balancing and optimization, increased from $57.78/MWh in 2003 to
$59.19/MWh in 2004.
Sales of purchased power for hedging and optimization decreased in the
three months ended March 31, 2004, due primarily to netting approximately $370.5
of sales of purchased power with purchase power expense in the quarter ended
March 31, 2004, from the adoption of EITF Issue No. 03-11 on a prospective basis
in the fourth quarter of 2003 partly offset by higher volumes and higher
realized prices on hedging, balancing and optimization activities. Without this
netting, sales of purchased power would have increased by $69.2 or 10%.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Oil and gas sales................................................... $ 24.6 $ 25.9 $ (1.3) (5.0)%
Sales of purchased gas for hedging and optimization................. 352.7 327.5 25.2 7.7%
----------- ----------- -----------
Total oil and gas production and marketing revenue............... $ 377.3 $ 353.4 $ 23.9 6.8%
=========== =========== ===========
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption decreased primarily as a result of asset
sales from $125.2 to $80.1 in 2004. Before intercompany eliminations, oil and
gas sales decreased by 31% or $46.4 to $104.7 in 2004 from $151.1 in 2003 due
primarily to 27% lower production following asset sales in 2003 and due to 5.2%
lower average realized oil and natural gas pricing in 2004.
Sales of purchased gas for hedging and optimization increased during 2004
due to higher volumes as compared to the same period in 2003.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Realized gain on power and gas trading transactions, net............ $ 17.4 $ 21.2 $ (3.8) (17.9)%
Unrealized loss on power and gas transactions, net.................. (4.9) (0.8) (4.1) 512.5%
----------- ----------- -----------
Mark-to-market activities, net................................... $ 12.5 $ 20.4 $ (7.9) (38.7)%
=========== =========== ===========
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
including positions accounted for as trading under EITF Issue No. 02-3, "Issues
Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" ("EITF Issue No. 02-3") and other mark-to-market
activities. These commodity positions represent a small portion of our overall
commodity contract position. Realized revenue represents the portion of
contracts actually settled, while unrealized revenue represents changes in the
fair value of open contracts, and the ineffective portion of cash flow hedges.
-37-
The decrease in mark-to-market activities revenue in the three months ended
March 31, 2004, as compared to the same period in 2003 is due primarily to $9.0
in mark-to-market losses incurred on transactions executed as part of the
Calpine Construction Finance Company L.P. ("CCFC I") refinancing in 2003.
Although these transactions were executed to support the cash flows of the CCFC
I entity, they are required to be accounted for on a mark-to-market basis under
GAAP. Losses on the CCFC I transactions were offset by increased mark-to-market
gains on other positions.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Other revenue....................................................... $ 27.0 $ 7.3 $ 19.7 269.9%
Other revenue increased during the three months ended March 31, 2004,
primarily due to an increase of $12.2 of revenue from Thomassen Turbine Systems,
("TTS"), which we acquired in February 2003.
Cost of Revenue
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Cost of revenue..................................................... $ 1,922.2 $ 2,000.8 $ (78.6) (3.9)%
The decrease in total cost of revenue is explained by category below.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Plant operating expense............................................. $ 175.8 $ 161.9 $ 13.9 8.6%
Transmission purchase expense....................................... 16.4 8.8 7.6 86.4%
Royalty expense..................................................... 5.9 5.4 0.5 9.3%
Purchased power expense for hedging and optimization................ 374.9 679.9 (305.0) (44.9)%
----------- ----------- -----------
Total electric generation and marketing expense.................. $ 573.0 $ 856.0 $ (283.0) 33.1%
=========== =========== ===========
Plant operating expense increased due to 5 new baseload power plants, 4 new
peaker facilities and 2 expansion projects completed subsequent to March 31,
2003. The addition of these units resulted in a 21% increase in consolidated
operating capacity.
Transmission purchase expense increased primarily due to additional power
plants achieving commercial operation subsequent to March 31, 2003.
Royalty expense increased primarily due to an increase in electric revenues
at the Geysers geothermal plants.
Purchased power expense for hedging and optimization decreased during the
three months ended March 31, 2004, as compared to the same period in 2003 due
primarily to netting $370.5 of purchased power expense against sales of
purchased power in the quarter ended March 31, 2004, from the adoption of EITF
Issue No. 03-11 in the fourth quarter of 2003, partly offset by higher volumes
and higher realized prices on hedging, balancing and optimization activities.
-38-
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Oil and gas production expense...................................... $ 20.6 $ 23.3 $ (2.7) (11.6)%
Oil and gas exploration expense..................................... 1.7 2.4 (0.7) (29.2)%
Oil and gas operating expense.................................... 22.3 25.7 (3.4) (13.2)%
Purchased gas expense for hedging and optimization.................. 360.5 316.9 43.6 13.8%
----------- ----------- -----------
Total oil and gas operating and marketing expense............. $ 382.8 $ 342.6 $ 40.2 11.7%
=========== =========== ===========
Oil and gas production expense decreased during the three months ended
March 31, 2004, as compared to the same period in 2003 primarily due to lower
production taxes as the result of lower oil and gas revenues and tight sands
formation tax refund plus lower lease operating expense primarily due to the
sale of properties in the fourth quarter of 2003.
Oil and gas exploration expense decreased primarily as a result of a
decrease in exploration activity.
Purchased gas expense for hedging and optimization increased during the
three months ended March 31, 2004, due to higher volumes as compared to the same
period in 2003.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Fuel Expense
Cost of oil and gas burned by power plants....................... $ 762.2 $ 643.4 $ 118.8 18.5%
Recognized (gain) loss on gas hedges............................. 0.5 (8.0) 8.5 (106.3)%
----------- ----------- -----------
Total fuel expense............................................ $ 762.7 $ 635.4 $ 127.3 20.0%
=========== =========== ===========
Cost of oil and gas burned by power plants increased during the three
months ended March 31, 2004, as compared to the same period in 2003 due to an
11% increase in gas-fired megawatt hours generated and 2% higher prices
excluding the effects of hedging, balancing and optimization.
Recognized (gain) loss on gas hedges decreased during the three months
ended March 31, 2004, as compared to the same period in 2003 due to unfavorable
gas price movements against our gas financial instrument positions.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Depreciation, depletion and amortization expense.................... $ 149.4 $ 133.8 $ 15.6 11.7%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to March
31, 2003.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Operating lease expense............................................. $ 27.8 $ 27.7 $ 0.1 0.4%
Operating lease expense was consistent with the prior year as the number of
operating leases did not change in 2004 as compared to 2003.
-39-
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Other cost of revenue............................................... $ 26.4 $ 5.3 $ 21.1 398.1%
Other cost of revenue increased during the three months ended March 31,
2004, as compared to the same period in 2003 due primarily to $10.6 of
additional expense from TTS and $8.8 of amortization expense incurred from the
adoption of Derivatives Implementation Group ("DIG") Issue No. C20, "Scope
Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in
Paragraph 10(b) regarding Contracts with a Price Adjustment Feature." In the
fourth quarter of 2003, we recorded a pre-tax mark-to-market gain of $293.4 as
the cumulative effect of a change in accounting principle. This gain is
amortized as expense over the respective lives of the two power sales contracts
from which the mark-to-market gains arose.
(Income)/Expenses
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
(Income) from unconsolidated investments in power projects.......... $ (2.5) $ (5.1) $ 2.6 (51.0)%
(Income) from unconsolidated investments in power projects decreased during
the three months ended March 31, 2004, as compared to the same period in 2003
primarily as a result of the sale of our 50 percent interest in the Gordonsville
Power Plant which occurred on November 26, 2003. During the three months ended
March 31, 2003, we realized $1.9 in income from our 50 percent interest in the
Gordonsville Power Plant.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Equipment cancellation and asset impairment charge.................. $ 2.4 $ 0.1 $ 2.3 2,300.0%
Equipment cancellation and asset impairment charge increased during the
three months ended March 31, 2004, as compared to the same period in 2003 as a
result of a $2.3 termination fee recorded in connection with the termination of
a purchase contract for heat recovery steam generators components.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Project development expense......................................... $ 7.7 $ 5.1 $ 2.6 51.0%
Project development expense increased during the three months ended March
31, 2004, primarily due to costs associated with a new project for which a power
sales contract is being sought.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Research and development expense.................................... $ 3.8 $ 2.4 $ 1.4 58.3%
Research and development expense increased during the three months ended
March 31, 2004, as compared to the same period in 2003 primarily due to
increased personnel expenses related to new research and development programs at
our Power Systems Mfg., LLC ("PSM") subsidiary.
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Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Sales, general and administrative expense $ 57.2 $ 43.7 $ 13.5 30.9%
Sales, general and administrative expense increased during the three months
ended March 31, 2004, primarily due to an increase in employee, consulting,
rent, insurance and other professional fees.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Interest expense.................................................... $ 254.8 $ 143.0 $ 111.8 78.2%
Interest expense increased partially as a result of new plants that entered
commercial operations (at which point capitalization of interest expense
ceases). Interest capitalized decreased from $118.5 for the three months ended
March 31, 2003, to $108.5 for the three months ended March 31, 2004.
Additionally, we incurred approximately $12.5 in accelerated amortization of
deferred financing costs due to the early refinancing of the CCFC II debt on
March 23, 2004. The remaining increase relates to a 15% increase in average
indebtedness, an increase in the amortization of terminated interest rate swaps
and the recording of interest expense on debt to the three Calpine Capital
Trusts due to the adoption of FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of ARB 51" ("FIN 46")
prospectively on October 1, 2003. See Note 2 of the Notes to Consolidated
Condensed Financial Statements for a discussion of our adoption of FIN 46. We
expect that interest expense will continue to increase and the amount of
interest capitalized will decrease in future periods as our plants in
construction are completed.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Distributions on Trust Preferred Securities......................... $ -- $ 15.7 $ (15.7) (100.0)%
As a result of the deconsolidation of the three Calpine Capital Trusts upon
adoption of FIN 46 as of October 1, 2003, the distributions paid on the Trust
Preferred Securities during the three months ended March 31, 2004, were no
longer recorded on our books and were replaced by interest expense on our debt
to the Calpine Capital Trusts.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Interest (income)................................................... $ (12.1) $ (8.0) $ (4.1) 51.3%
Interest (income) increased during the three months ended March 31, 2004,
due to an increase in cash and equivalents and restricted cash balances as
compared to the same period in 2003.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Minority interest expense........................................... $ 8.4 $ 2.3 $ 6.1 265.2%
Minority interest expense increased during the three months ended March 31,
2004, as compared to the same period in 2003 primarily due to an increase of
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$6.5 of minority interest expense associated with the Calpine Power Income Fund
("CPIF"), which had an initial public offering in August 2002. During 2003 as a
result of a secondary offering of Calpine's interests in CPIF, Calpine decreased
its ownership interests to 30%, thus increasing minority interest expense.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Other expense (income).............................................. $ (19.3) $ 34.6 $ (53.9) (155.8)%
Other expense (income) was $53.9 higher in the quarter ended March 31,
2004, due primarily to a foreign currency translation gain of $10.0, a gain on
the sale of a variety of oil and gas properties of $6.2 and a favorable warranty
settlement in the amount of $5.1. This compares to a $25.2 foreign currency
translation loss and $4.4 in letter of credit fees in the corresponding period
in 2003.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Benefit for income taxes............................................ $ (85.9) $ (16.9) $ (69.0) 408.3%
For the three months ended March 31, 2004, the effective rate increased to
48% as compared to 25% for the three months ended March 31, 2003. This effective
rate variance is due to the consideration of estimated year-end earnings in
estimating the quarterly effective rate and due to the effect of significant
permanent items.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Discontinued operations, net of tax................................. $ 22.9 $ (1.0) $ 23.9 2,390.0%
In the first quarter of 2004, our discontinued operations was comprised
primarily of the gain from the sale of our Lost Pines 1 Power Project. There
were no assets held for sale as of March 31, 2003.
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Cumulative effect of a change in accounting principle, net of tax... $ -- $ 0.5 $ (0.5) (100.0)%
The cumulative effect of a change in accounting principle, net of tax
effect in 2003 resulted from adopting SFAS No. 143, "Accounting for Asset
Retirement Obligations."
Three Months Ended
March 31,
------------------------
2004 2003 $ Change % Change
----------- ----------- ----------- --------
Net loss............................................................ $ (71.2) $ (52.0) $ (19.2) 36.9%
We recorded a net loss of $71.2 for the first quarter of 2004, compared to
a net loss of $52.0 for the same period last year. During the three months ended
March 31, 2004, gross profit decreased by $44.6, or 27%, to $120.5, compared to
the first quarter last year. This decrease is the result of lower spark spreads
realized during the quarter and additional costs associated with new power
plants coming on line. For the first quarter of 2004, we generated 21.1 million
megawatt-hours, which equated to a capacity factor of 50.3%, and realized an
average spark spread of $21.05 per megawatt-hour. For the same period in 2003,
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we generated 19.1 million megawatt-hours, which equated to a capacity factor of
55.2%, and realized an average spark spread of $23.09 per megawatt-hour.
Additional power plant costs include a $15.6 increase in depreciation expense, a
$13.9 increase in plant operating expense and a $7.6 increase in transmission
purchase expense. Also, in the first quarter of 2004, financial results were
affected by a $96.2 increase in interest expense and distributions on trust
preferred securities due to higher debt balances, and by the expensing of
deferred financing costs in connection with the CalGen refinancing. We recorded
$8.8 of amortization expense in other cost of revenue in the first quarter of
2004 related to a mark-to-market gain recognized in the fourth quarter of 2003
pursuant to adoption of Derivatives Implementation Group ("DIG") Issue No. C20,
"Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely
Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature."
Other income was $53.9 higher in the quarter ended March 31, 2004, compared
to the prior year due primarily to a foreign currency transaction gain of $10.0
in the current period. This compares to a $25.2 foreign currency transaction
loss in the corresponding period in 2003. Additionally, in the first quarter of
2004, we recognized a $23.0 after-tax gain in discontinued operations from the
sale of the Lost Pines 1 Power Project.
Liquidity and Capital Resources
Our business is capital intensive. Our ability to capitalize on growth
opportunities is dependent on the availability of capital on attractive terms.
The availability of such capital in today's environment is uncertain. To date,
we have obtained cash from our operations; borrowings under our term loan and
revolving credit facilities; issuance of debt, equity, trust preferred
securities and convertible debentures; proceeds from sale/leaseback
transactions; sale or partial sale of certain assets; contract monetizations and
project financing. We have utilized this cash to fund our operations, service or
prepay debt obligations, fund acquisitions, develop and construct power
generation facilities, finance capital expenditures, support our hedging,
balancing, optimization and trading activities at CES, and meet our other cash
and liquidity needs. Our strategy is also to reinvest our cash from operations
into our business development and construction program or to use it to reduce
debt, rather than to pay cash dividends. As discussed below, we have a
liquidity-enhancing program underway to fund the completion of our current
construction portfolio, for refinancing and for general corporate purposes.
In November 2004 our $2.5 billion secured revolving construction financing
facility through our wholly owned subsidiary CCFC II (renamed "CalGen") was
scheduled to mature, requiring us to refinance this indebtedness. As of December
31, 2003, there was $2.3 billion outstanding under this facility including $53.2
million of letters of credit. On March 23, 2004, CalGen completed its offering
of secured institutional term loans and secured notes, which refinanced the
CalGen facility. We realized total proceeds from the offering in the amount of
$2.4 billion, before transaction costs and fees. See Note 6 of the Notes to
Consolidated Condensed Financial Statements for more information regarding this
offering.
The holders of our 4% Convertible Senior Notes Due 2006 ("2006 Convertible
Senior Notes") have a right to require us to repurchase them at 100% of their
principal amount plus any accrued and unpaid interest on December 26, 2004. We
can effect such a repurchase with cash, shares of Calpine stock or a combination
of the two. In 2003 and 2004 we repurchased in open market and privately
negotiated transactions totaling approximately $1,127.9 million of the
outstanding principal amount of 2006 Convertible Senior Notes, primarily with
proceeds of the July 2003 offerings and through equity swaps and with the
proceeds of our 4.75% Contingent Convertible Senior Notes Due 2023 ("2023
Convertible Notes") offering, and the February 9, 2004, tender offer, in which
we initiated a cash tender offer for all of the outstanding 2006 Convertible
Senior Notes for a price of par plus accrued interest. Approximately $409.4
million aggregate principal amount of the 2006 Convertible Senior Notes were
tendered pursuant to the tender offer, for which we paid a total of $412.8
million (including accrued interest of $3.4 million). At March 31, 2004, 2006
Convertible Senior Notes in the aggregate principal amount of $72.1 million
remain outstanding.
On November 6, 2003, we priced our separate offerings of 2023 Convertible
Notes and Second Priority Senior Secured Notes. The latter offering was for
$400.0 million of 9.875% Second Priority Senior Secured Notes Due 2011, offered
at 98.01% of par. This offering closed on November 18, 2003. We used the net
proceeds from this offering to purchase outstanding senior notes. The other
offering consisted of $650.0 million of 4.75% Contingent Convertible Senior
Notes Due 2023, which included the exercise of $50.0 million of an option to
purchase additional 2023 Convertible Notes granted to one of the initial
purchasers. The 2023 Convertible Notes are convertible into cash and shares of
Calpine common stock at an initial conversion price of $6.50 per share, which
represents a 38% premium on the November 6, 2003 New York Stock Exchange closing
price of $4.71 per Calpine common share. This offering closed on November 14,
2003. Net proceeds from this offering were used to repurchase our outstanding
2006 Convertible Senior Notes. In addition, on January 9, 2004, we received
funding on an additional $250.0 million aggregate principal amount of the 2023
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Convertible Notes pursuant to the exercise in full by one of the initial
purchasers of its remaining option to purchase additional 2023 Convertible
Notes, the net proceeds of which were also used to repurchase our outstanding
2006 Convertible Senior Notes pursuant to the tender offer described above.
In addition, $276.0 million of our outstanding HIGH TIDES are scheduled to
be remarketed no later than November 1, 2004, $360.0 million of our HIGH TIDES
are scheduled to be remarketed no later than February 1, 2005 and $517.5 million
of our HIGH TIDES are scheduled to be remarketed no later than August 1, 2005.
In the event of a failed remarketing, the relevant HIGH TIDES will remain
outstanding as convertible securities at a term rate equal to the treasury rate
plus 6% per annum and with a term conversion price equal to 105% of the average
closing price of our common stock for the five consecutive trading days after
the applicable final failed remarketing termination date. While a failed
remarketing of our HIGH TIDES would not have a material effect on our liquidity
position, it would impact our calculation of diluted earnings per share and
increase our interest expense.
We expect to have sufficient liquidity from cash flow from operations,
borrowings available under lines of credit, access to sale/leaseback and project
financing markets, sale or monetization of certain assets and cash balances to
satisfy all obligations under our outstanding indebtedness, and to fund
anticipated capital expenditures and working capital requirements for the next
twelve months. On March 31, 2004, our liquidity totaled approximately $1.4
billion. This included cash and cash equivalents on hand of $0.6 billion,
current portion of restricted cash and cash escrowed for debt repurchases of
approximately $0.4 billion and approximately $0.4 billion of borrowing capacity
under our various credit facilities.
Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Three Months Ended
March 31,
-----------------------------
2004 2003
------------- -------------
( In thousands)
Beginning cash and cash equivalents................................. $ 991,806 $ 579,486
Net cash provided by (used in):
Operating activities............................................. (173,230) 165,367
Investing activities............................................. (71,371) (483,629)
Financing activities............................................. (160,091) 112,543
Effect of exchange rates changes on cash and cash equivalents.... (4,310) 4,290
------------ -------------
Net decrease in cash and cash equivalents........................ (409,002) (201,429)
------------ -------------
Ending cash and cash equivalents.................................... $ 582,804 $ 378,057
============ =============
Operating activities for the three months ended March 31, 2004, used net
cash of $173.2 million, compared to having provided $165.4 million for the same
period in 2003. In the first quarter of 2004, there was 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 posted to support CES contracting
activity, 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.
In the first quarter of 2003, there was a $56.6 million use of funds from
net changes in operating assets and liabilities. Adjustments to reconcile net
income to net cash provided by operating activities had the effect of lowering
operating cash flow by $238.3 million between years. The increase in the tax
benefit (decrease in deferred taxes) during 2004 contributed to $102.7 million
of this difference. Additionally, an increase in 2004 of $67.4 million in gains
from foreign exchange transactions and asset sales further contributed to the
decrease in operating cash flow between periods. Finally, the change in net
derivative liability comprised primarily of mark-to-market activity constitutes
the majority of the remaining difference.
Investing activities for the three months ended March 31, 2004, consumed
net cash of $71.4 million, as compared to $483.6 million in the same period of
2003. Capital expenditures for the completion of our power facilities decreased
in 2004, as there were fewer projects under construction. Investing activities
in 2004 reflect the receipt of $176.9 million from the sale our Lost Pines Power
Plant and certain oil and gas properties, as compared to $9.1 million of
proceeds from other disposals in the prior year. We also reported a $187.5
million increase in cash used for acquisitions, as we used the proceeds from the
Lost Pines sale and cash on hand to purchase the Los Brazos Power Plant, the
remaining 50% interest in the Aries Power Plant, and the remaining 20% interest
in Calpine Cogeneration Company's fleet of plants. Finally, the $346.3 million
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decrease in restricted cash served as an investing activity inflow in 2004. The
balance decreased in connection with the repurchase of debt with restricted cash
(primarily the Convertible Senior Notes Due 2006.)
Financing activities for the three months ended March 31, 2004, used $160.1
million, compared to having provided $112.5 million for the same period in 2003.
We continued our refinancing program in the first quarter of 2004, by raising
$2.4 billion to repay $2.3 billion of CCFC II project financing. In the first
quarter of 2004, we also raised $250 million from the issuance of Convertible
Senior Notes Due 2023 pursuant to an option exercise, and $315.1 million from
various project financings, and we used $586.9 million of proceeds from
convertible senior notes offerings to repurchase the majority of outstanding
Convertible Senior Notes Due 2006 that come due in December.
Counterparties and Customers -- Our customer and supplier base is
concentrated within the energy industry. Additionally, we have exposure to
trends within the energy industry, including declines in the creditworthiness of
our marketing counterparties. Currently, multiple companies within the energy
industry are in bankruptcy or have below investment grade credit ratings. We
believe that our current credit exposure to other companies in the energy
industry is not significant either by individual company or in the aggregate.
Letter of Credit Facilities -- At March 31, 2004 and December 31, 2003, we
had approximately $512.1 million and $410.8 million, respectively, in letters of
credit outstanding under various credit facilities to support CES risk
management and other operational and construction activities. Of the total
letters of credit outstanding, $323.0 million and $272.1 million were in
aggregate issued under our cash collateralized letter of credit facility and the
corporate revolving credit facility at March 31, 2004 and December 31, 2003,
respectively.
CES Margin Deposits and Other Credit Support -- As of March 31, 2004 and
December 31, 2003, CES had deposited net amounts of $249.2 million and $188.0
million, respectively, in cash as margin deposits with third parties and had
letters of credit outstanding of $14.5 million and $14.5 million, respectively.
CES uses these margin deposits and letters of credit as credit support for the
gas procurement and risk management activities it conducts on Calpine's behalf.
Future cash collateral requirements may increase based on the extent of our
involvement in derivative activities and movements in commodity prices and also
based on our credit ratings and general perception of creditworthiness in this
market. While we believe that we have adequate liquidity to support CES's
operations at this time, it is difficult to predict future developments and the
amount of credit support that we may need to provide as part of our business
operations.
Capital Availability -- Access to capital for many in the energy sector,
including us, has been restricted since late 2001. While we have been able to
access the capital and bank credit markets in this new environment, it has been
on significantly different terms than in the past. In particular, our senior
working capital facility and term loan financings and the majority of our debt
securities offered and sold in this period, have been secured by certain of our
assets and equity interests. While we believe we will be successful in
refinancing all debt before maturity, the terms of financing available to us now
and in the future may not be attractive to us and the timing of the availability
of capital is uncertain and is dependent, in part, on market conditions that are
difficult to predict and are outside of our control.
During the three months ended March 31, 2004:
o We completed the $250 million, non-recourse project financing facility
to fund the construction of our 600-megawatt Rocky Mountain Energy
Center.
o Our wholly owned subsidiary Calpine Generating Company, LLC
("CalGen"), formerly Calpine Construction Finance Company II, LLC
("CCFC II") completed its offering of secured institutional term loans
and secured notes, totaling $2.4 billion before transaction costs and
fees. Net proceeds from the offering were used to refinance amounts
outstanding under the $2.5 billion CCFC II revolving construction
credit facility, which was scheduled to mature in November 2004, and
to pay fees and transaction costs associated with the refinancing.
o One of the initial purchasers of the 2023 Convertible Notes exercised
in full its option to purchase an additional $250.0 million of these
notes.
o We repurchased approximately $178.5 million in principal amount of the
2006 Convertible Senior Notes in exchange for approximately $177.5
million in cash. Additionally, on February 9, 2004, we made a cash
tender offer, which expired on March 9, 2004, for any and all of the
then still outstanding 2006 Convertible Senior Notes at a price of par
plus accrued interest. On March 10, 2004, we paid an aggregate amount
of $412.8 million for the tendered 2006 Convertible Senior Notes which
-45-
included accrued interest of $3.4 million. At March 31, 2004, 2006
Convertible Senior Notes in the aggregate principal amount of $72.1
million remained outstanding.
Asset Sales -- As a result of the significant contraction in the
availability of capital for participants in the energy sector, we have adopted a
strategy of conserving our core strategic assets and disposing of certain less
strategically important assets, which serves partially to strengthen our balance
sheet through repayment of debt. Set forth below are the completed asset
disposals during the period:
On January 15, 2004, we completed the sale of our 50-percent undivided
interest in the 545 megawatt Lost Pines 1 Power Project to GenTex Power
Corporation, an affiliate of the Lower Colorado River Authority ("LCRA"). Under
the terms of the agreement, we received a cash payment of $146.8 million and
recorded a gain before taxes of $35.3 million. In addition, CES entered into a
tolling agreement with LCRA to purchase 250 megawatts of electricity through
December 31, 2004. At December 31, 2003, our undivided interest in the Lost
Pines facility was classified as "held for sale" and all current and historical
results reclassified to discontinued operations (See Note 8 of the Notes to
Consolidated Condensed Financial Statements).
On February 18, 2004, one of our wholly owned subsidiaries closed on the
sale of natural gas properties to Calpine Natural Gas Trust ("CNG Trust"). We
received consideration of Cdn$40.5 million (US$30.9 million). We hold 25% of the
outstanding trust units of CNG Trust and account for the investment using the
equity method.
We believe that our completion of the financing and asset sales liquidity
transactions described above in difficult conditions affecting the market, and
our sector in general, demonstrate our probable ability to have access to the
capital markets on acceptable terms in the future, although availability of
capital has tightened significantly throughout the power generation industry
and, therefore, there can be no assurance that we will have access to capital in
the future as and when we may desire.
Off-Balance Sheet Commitments -- In accordance with Accounting Principles
Board ("APB") Opinion No. 18, "The Equity Method of Accounting For Investments
in Common Stock" and FASB Interpretation No. 35, "Criteria for Applying the
Equity Method of Accounting for Investments in Common Stock (An Interpretation
of APB Opinion No. 18)," the debt on the books of our unconsolidated investments
in power projects is not reflected on our Consolidated Condensed Balance Sheet.
At March 31, 2004, investee debt was approximately $289.6 million. Based on our
pro rata ownership share of each of the investments, our share would be
approximately $61.5 million. However, all such debt is non-recourse to us. See
Note 7 of the Notes to Consolidated Condensed Financial Statements for
additional information on our equity method investments in power projects and
oil and gas properties.
We own a 32.3% interest in the unconsolidated equity method investee
Androscoggin Energy LLC ("AELLC"). AELLC owns the 160-MW Androscoggin Energy
Center located in Maine and has construction debt of $60.1 million outstanding
as of March 31, 2004. The debt is non-recourse to Calpine Corporation (the
"AELLC Non-Recourse Financing"). On March 31, 2004, and December 31, 2003, our
investment balance was $14.2 million and $11.8 million, respectively, and our
notes receivable balance due from AELLC was $14.8 million and $13.3 million,
respectively. On and after August 8, 2003, AELLC received letters from the
lenders claiming that certain events of default have occurred under the credit
agreement for the AELLC Non-Recourse Financing, including, among other things,
that the project has been and remains in default under its debt agreement
because the lending syndication had declined to extend the date for the
conversion of the construction loan to a term loan. AELLC disputes the purported
defaults. Also, the steam host for the AELLC project, International Paper
Company ("IP"), filed a complaint against AELLC in October 2000, which is
discussed in Note 12 of the Notes to Consolidated Condensed Financial
Statements. IP's complaint has been a complicating factor in converting the
construction debt to long term financing. As a result of these events, we have
reviewed our investment and notes receivable balances and believe that the
assets are not impaired. We further believe that AELLC will be able to convert
the construction loan to a term loan.
Credit Considerations -- On March 22, 2004, S&P assigned its B corporate
credit rating (with negative outlook) to our wholly owned subsidiary CalGen.
Concurrently, S&P assigned its B+ rating and its 1 recovery rating to CalGen's
$235.0 million First Priority Secured Floating Rate Notes Due 2009 and the
$600.0 million First Priority Secured Term Loans due 2009. S&P assigned its B
rating and its 2 recovery rating to CalGen's $640.0 million Second Priority
Secured Floating Rate Notes Due 2010 and the $100.0 million Second Priority
Secured Term Loans due 2010. S&P also assigned its CCC+ rating and its 5
recovery rating to CalGen's $680.0 million Third Priority Secured Floating Rate
Notes Due 2011 and the $150.0 million Third Priority Secured Notes Due 2011.
Capital Spending -- Development and Construction
-46-
Construction and development costs in process consisted of the following at
March 31, 2004 (dollars in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP (1) CIP Costs Equipment
-------- ----------- ----------- ----------- ----------
Projects in active construction.................... 13 $ 4,684,403 $ 1,537,067 $ -- $ --
Projects in advanced development................... 15 754,280 623,696 128,708 --
Projects in suspended development.................. 5 463,094 203,185 8,753 --
Projects in early development...................... 3 -- -- 8,932 12,280
Other capital projects............................. NA 50,620 31 -- --
Unassigned equipment............................... NA -- -- -- 54,789
----------- ----------- --------- ----------
Total construction and development costs........ $ 5,952,397 $ 2,363,979 $ 146,393 $ 67,069
=========== =========== ========= ==========
- ----------
<FN>
(1) Construction in Progress ("CIP").
</FN>
Projects in Active Construction -- The 13 projects in active construction
are estimated to come on line from May 2004 to June 2007. These projects will
bring on line approximately 6,495 MW of base load capacity (7,685 MW base load
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, 2004, the estimated funding requirements to complete
these projects, net of expected project financing proceeds, is approximately
$1.2 billion.
Projects in Advanced Development -- There are 15 projects in advanced
development. These projects will bring on line approximately 6,735 MW of base
load capacity (7,952 MW base load with peaking capacity). Interest and other
costs related to the development activities necessary to bring these projects to
their intended use are being capitalized. However, the capitalization of
interest has been suspended on two projects for which development activities are
complete but construction will not commence until a power purchase agreement and
financing are obtained. The estimated cost to complete the 15 projects in
advanced development is approximately $4.4 billion. Our current plan is to
project finance these costs as power purchase agreements are arranged.
Suspended Development Projects -- Due to current electric market
conditions, we have ceased capitalization of additional development costs and
interest expense on certain development projects on which work has been
suspended. Capitalization of costs may recommence as work on these projects
resumes, if certain milestones and criteria are met. These projects would bring
on line approximately 2,569 MW of base load capacity (3,029 MW base load with
peaking capacity). The estimated cost to complete the five projects is
approximately $1.5 billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then all costs, including interest costs are expensed. The
projects in early development with capitalized costs relate to three projects
and include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development as well as software developed for internal use.
Unassigned Equipment -- As of March 31, 2004, we had made progress payments
on 4 turbines, 1 heat recovery steam generator, and other equipment with an
aggregate carrying value of $67.1 million. This unassigned equipment is
classified on the balance sheet as other assets because it is not assigned to
specific development and construction projects. We are holding this equipment
for potential use on future projects. It is possible that some of this
unassigned equipment may eventually be sold, potentially in combination with our
engineering and construction services. For equipment that is not assigned to
development or construction projects, interest is not capitalized.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144. We review our unassigned equipment for potential impairment
based on probability-weighted alternatives of utilizing the equipment for future
-47-
projects versus selling the equipment. Utilizing this methodology, we do not
believe that the equipment not committed to sale is impaired.
Performance Metrics
In understanding our business, we believe that certain non-GAAP operating
performance metrics are particularly important. These are described below:
Total deliveries of power.
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.
-48-
The table below presents, the operating performance metrics discussed
above.
Three Months Ended March 31,
-----------------------------
2004 2003
-------------- -------------
(In thousands)
Operating Performance Metrics:
Total deliveries of power:
MWh generated................................................. 21,050 19,100
HBO and trading MWh sold...................................... 19,598 17,520
------------- -------------
MWh delivered................................................. 40,648 36,620
============= =============
Average availability.............................................. 92% 88%
Average baseload capacity factor:
Average total MW in operation................................. 21,852 18,108
Less: Average MW of pure peakers.............................. 2,951 2,219
------------- -------------
Average baseload MW in operation.............................. 18,901 15,889
Hours in the period........................................... 2,184 2,160
Potential baseload generation................................. 41,280 34,320
Actual total generation....................................... 21,050 19,100
Less: Actual pure peakers' generation......................... 273 171
------------- -------------
Actual baseload generation.................................... 20,777 18,929
Average baseload capacity factor.............................. 50.3% 55.2%
Average heat rate for gas-fired power plants
(excluding peakers) (Btu's/KWh):
Not steam adjusted............................................ 8,167 7,968
Steam adjusted................................................ 7,115 7,229
Average all-in realized electric price:
Electricity and steam revenue................................. $ 1,245,887 $ 1,103,535
Spread on sales of purchased power for
hedging and optimization.................................... 5,089 1,335
------------- -------------
Adjusted electricity and steam revenue (in thousands)......... $ 1,250,976 $ 1,104,870
MWh generated (in thousands).................................. 21,050 19,100
Average all-in realized electric price per MWh................ $ 59.43 $ 57.85
Average cost of natural gas:
Cost of oil and natural gas burned by power plants
(in thousands).............................................. $ 770,454 $ 624,849
Fuel cost elimination......................................... 80,110 110,334
------------- -------------
Adjusted fuel expense......................................... $ 850,564 $ 735,183
Million Btu's ("MMBtu") of fuel consumed by
generating plants (in thousands)............................ 150,357 122,936
Average cost of natural gas per MMBtu......................... $ 5.66 $ 5.98
MWh generated (in thousands).................................. 21,050 19,100
Average cost of adjusted fuel expense per MWh................. $ 40.41 $ 38.49
Average spark spread:
Adjusted electricity and steam revenue (in thousands)......... $ 1,250,976 $ 1,104,870
Less: Adjusted fuel expense (in thousands).................... 850,564 735,183
------------- -------------
Spark spread (in thousands)................................... $ 400,412 $ 369,687
MWh generated (in thousands).................................. 21,050 19,100
Average spark spread per MWh.................................. $ 19.02 $ 19.36
Add: Equity gas contribution(1)............................... $ 42,684 $ 71,275
Spark spread with equity gas benefits (in thousands).......... $ 443,096 $ 440,962
Average spark spread with equity gas benefits per MWh......... $ 21.05 $ 23.09
Average plant operating expense ("POX") per
normalized MWh:
Average total consolidated MW in operations................... 21,852 18,108
Hours in the period........................................... 2,184 2,160
Total potential MWh........................................... 47,725 39,113
Normalized MWh (at 70% capacity factor)....................... 33,408 27,379
Plant operating expense (POX)................................. $ 175,834 $ 161,929
POX per normalized MWh........................................ $ 5.26 $ 5.91
- ----------
-49-
(1) Equity gas contribution margin:
Three Months Ended March 31,
-----------------------------
2004 2003
------------- -------------
(In thousands)
Oil and gas sales............................... $ 24,581 $ 25,911
Add: Fuel cost eliminated in consolidation...... 80,110 110,334
------------ -----------
Subtotal..................................... $ 104,691 $ 136,245
Less: Oil and gas operating expense............. 22,328 25,661
Less: Depletion, depreciation and amortization.. 39,679 39,309
------------ -----------
Equity gas contribution margin.................. $ 42,684 71,275
MWh generated (in thousands).................... 21,050 19,100
Equity gas contribution margin per MWh.......... $ 2.03 $ 3.73
The table below provides additional detail of total mark-to-market
activity. For the three months ended March 31, 2004 and 2003, mark-to-market
activity, net consisted of (dollars in thousands):
2004 2003
---------- ---------
Mark-to-market activity, net
Realized:
Power activity
"Trading Activity" as defined in EITF No. 02-03.. $ 18,708 $ 14,836
Other mark-to-market activity(1)................. (1,171) --
--------- ---------
Total realized power activity.................. $ 17,537 $ 14,836
========= =========
Gas activity
"Trading Activity" as defined in EITF No. 02-03.. $ (74) $ 6,378
Other mark-to-market activity(1)................. -- --
--------- ---------
Total realized gas activity.................... $ (74) $ 6,378
========= =========
Total realized activity:
"Trading Activity" as defined in EITF No. 02-03.. $ 18,634 $ 21,214
Other mark-to-market activity(1)................. (1,171) --
--------- ---------
Total realized activity........................ $ 17,463 $ 21,214
========= =========
Unrealized:
Power activity
"Trading Activity" as defined in EITF No. 02-03.. $ (693) $ (1,881)
Ineffectiveness related to cash flow hedges...... (540) (3,026)
Other mark-to-market activity(1)................. (9,795) --
--------- ---------
Total unrealized power activity................ $ (11,028) $ (4,907)
========= =========
Gas activity
"Trading Activity" as defined in EITF No. 02-03.. $ 637 $ (1,977)
Ineffectiveness related to cash flow hedges...... 5,446 6,113
Other mark-to-market activity(1)................. -- --
--------- ---------
Total unrealized gas activity.................. $ 6,083 $ 4,136
========= =========
Total unrealized activity:
"Trading Activity" as defined in EITF No. 02-03..... $ (56) $ (3,858)
Ineffectiveness related to cash flow hedges......... 4,906 3,087
Other mark-to-market activity(1).................... (9,795) --
--------- ---------
Total unrealized activity........................ $ (4,945) $ (771)
========== =========
Total mark-to-market activity:
"Trading Activity" as defined in EITF No. 02-03..... $ 18,578 $ 17,356
Ineffectiveness related to cash flow hedges......... 4,906 3,087
Other mark-to-market activity(1).................... (10,966)
--------- ---------
Total mark-to-market activity.................... $ 12,518 $ 20,443
========= =========
- ----------
(1) Activity related to our assets but does not qualify for hedge accounting.
-50-
Overview
Summary of Key Activities
Finance - New Issuances
Date Amount Description
- ------------ --------------- --------------------------------------------
1/9/04 $250.0 million Initial purchasers of the 2023 Convertible
Notes exercised in full their purchase
option
2/20/04 $250.0 million Completed a non-recourse project financing
for Rocky Mountain Energy Center at a rate
of LIBOR plus 250 basis points
3/23/04 $2.4 billion CalGen, formerly CCFC II, completed its
offering of secured term loans and secured
notes
Finance - Repurchases
Date Amount Description
- ------------ --------------- --------------------------------------------
1/04-3/04 $178.5 million Repurchased $178.5 million in principal of
our outstanding 2006 Convertible Senior
Notes that can be put to the Company in
exchange for $177.5 million in cash
3/10/04 $412.8 million Paid an aggregate of $412.8 million for the
cash tender offer of the 2006 Convertible
Senior Notes
3/24/04 $9.0 million Repurchased $9.0 million in principal of
8 1/2% Senior Notes Due 2011 and $11.0
million in principal of 7 3/4% Senior
Notes Due 2009 for cash of $14.8 million
Other:
Date Description
- ------------ ---------------------------------------------------------------
1/2004 Completed sale of 50-percent interest in Lost Pines 1 Power
Project for a cash payment of $146.8 million
1/2004 CES concluded a settlement with the Commodity Futures Trading
Commission and paid a civil monetary penalty in the amount of
$1.5 million
2/2004 Closed on the sale of natural gas properties to CNG Trust for
consideration of Cdn$40.5 million (US$30.9 million)
2/2004 Entered into a one-year agreement with Cleco Power LLC to
supply up to 500 megawatts of power
2/2004 Entered into five power sales contracts to supply
approximately 350 megawatts of electricity to five New
England-based electric distribution companies for delivery in
2004
3/2004 Entered into a 20-year purchased power agreement to provide 365
megawatts of electric power to Xcel Energy
3/2004 Acquired the remaining 50-percent interest in the Aries Power
Plant from Aquila, Inc.
3/2004 Completed the acquisition of the remaining 20 percent interest
in Calpine Cogeneration Company for approximately $2.5 million
3/2004 Entered into a three-year power sales agreement with Safeway
Inc. to supply approximately 100 megawatts to Safeway
facilities throughout California
3/2004 Closed on the purchase of Brazos Valley Power Plant for
approximately $175.0 million
Power Plant Development and Construction:
Date Project Description
- ------------ ------------------------------ --------------------------
1/2004 Morgan Energy Center Expansion Commercial Operation
California Power Market
California Refund Proceeding. On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric
Company under Section 206 of the Federal Power Act alleging, among other things,
-51-
that the markets operated by the California Independent System Operator
("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. In
addition to commencing an inquiry regarding the market structure, FERC
established a refund effective period of October 2, 2000, to June 19, 2001, for
sales made into those markets.
On December 12, 2002, the Administrative Law Judge ("ALJ") issued a
Certification of Proposed Finding on California Refund Liability ("December 12
Certification") making an initial determination of refund liability. On March
26, 2003, FERC also issued an order adopting many of the ALJ's findings set
forth in the December 12 Certification (the "March 26 Order"). In addition, as a
result of certain findings by the FERC staff concerning the unreliability or
misreporting of certain reported indices for gas prices in California during the
refund period, FERC ordered that the basis for calculating a party's potential
refund liability be modified by substituting a gas proxy price based upon gas
prices in the producing areas plus the tariff transportation rate for the
California gas price indices previously adopted in the refund proceeding. We
believe, based on the available information, that any refund liability that may
be attributable to us will increase modestly, from approximately $6.2 million to
$8.4 million, after taking the appropriate set-offs for outstanding receivables
owed by the CalPX and CAISO to us. We have fully reserved the amount of refund
liability that by our analysis would potentially be owed under the refund
calculation clarification in the March 26 order. The final determination of the
refund liability is subject to further Commission proceedings to ascertain the
allocation of payment obligations among the numerous buyers and sellers in the
California markets. At this time, we are unable to predict the timing of the
completion of these proceedings or the final refund liability. Thus the impact
on our business is uncertain at this time.
On April 26, 2004, Dynegy Inc. entered into a settlement of the California
Refund Proceeding and other proceedings with California governmental entities
and the three California investor-owned utilities. The California governmental
entities include the Attorney General, the California Public Utilities
Commission, the California Department of Water Resources ("CDWR"), and the
California Electricity Oversight Board. Also, on April 27, 2004, The Williams
Companies, Inc. ("Williams") entered into a settlement of the California Refund
Proceeding and other proceedings with the three California investor-owned
utilities; previously, Williams had entered into a settlement of the same
matters with the California governmental entities. The Williams settlement with
the California governmental entities was similar to the settlement that we
entered into with the California governmental entities on April 22, 2002. Our
settlement was approved by FERC on March 26, 2004, in an order which partially
dismissed us from the California Refund Proceeding to the extent that any
refunds are owed for power sold by us to CDWR or any other agency of the State
of California.
FERC Investigation into Western Markets. On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western United States. This investigation was initiated as a
result of allegations that Enron and others used their market position to
distort electric and natural gas markets in the West. The scope of the
investigation is to consider whether, as a result of any manipulation in the
short-term markets for electric energy or natural gas or other undue influence
on the wholesale markets by any party since January 1, 2000, the rates of the
long-term contracts subsequently entered into in the West are potentially unjust
and unreasonable. FERC has stated that it may use the information gathered in
connection with the investigation to determine how to proceed on any existing or
future complaint brought under Section 206 of the Federal Power Act involving
long-term power contracts entered into in the West since January 1, 2000, or to
initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding
on its own initiative. On August 13, 2002, the FERC staff issued the Initial
Report on Company-Specific Separate Proceedings and Generic Reevaluations;
Published Natural Gas Price Data; and Enron Trading Strategies (the "Initial
Report") summarizing its initial findings in this investigation. There were no
findings or allegations of wrongdoing by us set forth or described in the
Initial Report. On March 26, 2003, the FERC staff issued a final report in this
investigation (the "Final Report"). The FERC staff recommended that FERC issue a
show cause order to a number of companies, including us, regarding certain power
scheduling practices that may have been be in violation of the CAISO's or
CalPX's tariff. The Final Report also recommended that FERC modify the basis for
determining potential liability in the California Refund Proceeding discussed
above. We believe that we did not violate these tariffs and that, to the extent
that such a finding could be made, any potential liability would not be
material.
Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject us to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per megawatt hour into markets operated by either the
CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may
have violated CAISO and CalPX tariff prohibitions. No individual market
participant was identified. We believe that we did not violate the CAISO and
-52-
CalPX tariff prohibitions referred to by FERC in this order; however, we are
unable to predict at this time the final outcome of this proceeding or its
impact on us.
CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our
Qualifying Facilities ("QF") contracts with PG&E provide that the CPUC has the
authority to determine the appropriate utility "avoided cost" to be used to set
energy payments for certain QF contracts by determining the short run avoided
cost ("SRAC") energy price formula. In mid-2000 our QF facilities elected the
option set forth in Section 390 of the California Public Utility Code, which
provides QFs the right to elect to receive energy payments based on the CalPX
market clearing price instead of the price determined by SRAC. Having elected
such option, we were paid based upon the PX zonal day-ahead clearing price ("PX
Price") from summer 2000 until January 19, 2001, when the PX ceased operating a
day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine
whether the PX Price was the appropriate price for the energy component upon
which to base payments to QFs which had elected the PX-based pricing option. The
CPUC at one point issued a proposed decision to the effect that the PX Price was
the appropriate price for energy payments under the California Public Utility
Code but tabled it, and a final decision has not been issued to date. Therefore,
it is possible that the CPUC could order a payment adjustment based on a
different energy price determination. On April 29, 2004, PG&E, The Utility
Reform Network, which is a consumer advocacy group, and the Office of Ratepayer
Advocates, which is an independent consumer advocacy department of the CPUC,
(collectively, the "PG&E Parties") filed a Motion for Briefing Schedule
Regarding True-Up of Payments to QF Switchers (the "April 29 Motion"). The April
29 Motion requests that the CPUC set a briefing schedule under the R.99-11-022
to determine refund liability of the QFs who had switched to the PX Price during
the period of June 1, 2000, until January 19, 2001. The PG&E Parties allege that
refund liability be determined using the methodology that has been developed
thus far in the California Refund Proceeding discussed above. We believe that
the PX Price was the appropriate price for energy payments and that the basis
for any refund liability based on the interim determination by FERC in the
California Refund Proceeding is unfounded, but there can be no assurance that
this will be the outcome of the CPUC proceedings.
Geysers Reliability Must Run Section 206 Proceeding. CAISO, California
Electricity Oversight Board, Public Utilities Commission of the State of
California, Pacific Gas and Electric Company, San Diego Gas & Electric Company,
and Southern California Edison (collectively referred to as the "Buyers
Coalition") filed a complaint on November 2, 2001 at the FERC requesting the
commencement of a Federal Power Act Section 206 proceeding to challenge one
component of a number of separate settlements previously reached on the terms
and conditions of "reliability must run" contracts ("RMR Contracts") with
certain generation owners, including Geysers Power Company, LLC, which
settlements were also previously approved by the FERC. RMR Contracts require the
owner of the specific generation unit to provide energy and ancillary services
when called upon to do so by the ISO to meet local transmission reliability
needs or to manage transmission constraints. The Buyers Coalition has asked FERC
to find that the availability payments under these RMR Contracts are not just
and reasonable. Geysers Power Company, LLC filed an answer to the complaint in
November 2001. To date, FERC has not established a Section 206 proceeding. The
outcome of this litigation and the impact on our business cannot be determined
at the present time.
Financial Market Risks
As we are primarily focused on generation of electricity using gas-fired
turbines, our natural physical commodity position is "short" fuel (i.e., natural
gas consumer) and "long" power (i.e., electricity seller). To manage forward
exposure to price fluctuation in these and (to a lesser extent) other
commodities, we enter into derivative commodity instruments.
The change in fair value of outstanding commodity derivative instruments
from January 1, 2004 through March 31, 2004, is summarized in the table below
(in thousands):
Fair value of contracts outstanding at January 1, 2004......... $ 76,541
Gains recognized or otherwise settled during the period(1)..... (8,675)
Changes in fair value attributable to new contracts............ (3,748)
Changes in fair value attributable to price movements.......... 44,364
-------------
Fair value of contracts outstanding at March 31, 2004(2).. $ 108,482
=============
- ----------
(1) Recognized losses from commodity cash flow hedges of $(8.8) million
(represents realized value of cash flow hedge activity of $(17.7) million
as disclosed in Note 9 of the Notes to Consolidated Condensed Financial
Statements, net of terminated derivatives of $(8.9) million) and $17.5
million realized gain on mark-to-market activity, which is reported in the
Consolidated Condensed Statements of Operations under mark-to-market
activities, net. (2) Net commodity derivative assets reported in Note 9 of
the Notes to Consolidated Condensed Financial Statements.
-53-
The fair value of outstanding derivative commodity instruments at March 31,
2004, based on price source and the period during which the instruments will
mature, are summarized in the table below (in thousands):
Fair Value Source 2004 2005-2006 2007-2008 After 2008 Total
- ------------------------------------------------------------ ---------- ---------- ---------- ---------- ----------
Prices actively quoted...................................... $ 71,947 $ 45,917 $ -- $ -- $ 117,864
Prices provided by other external sources................... (43,747) 47,628 6,298 (22,354) (12,175)
Prices based on models and other valuation methods.......... -- 776 7,976 (5,959) 2,793
---------- ---------- ---------- ---------- ----------
Total fair value......................................... $ 28,200 $ 94,321 $ 14,274 $ (28,313) $ 108,482
========== ========== ========== ========== ==========
Our risk managers maintain fair value price information derived from
various sources in our risk management systems. The propriety of that
information is validated by our Risk Control group. Prices actively quoted
include validation with prices sourced from commodities exchanges (e.g., New
York Mercantile Exchange). Prices provided by other external sources include
quotes from commodity brokers and electronic trading platforms. Prices based on
models and other valuation methods are validated using quantitative methods.
The counterparty credit quality associated with the fair value of
outstanding derivative commodity instruments at March 31, 2004, and the period
during which the instruments will mature are summarized in the table below (in
thousands):
Credit Quality 2004 2005-2006 2007-2008 After 2008 Total
- ------------------------------------------------------------ ---------- ---------- ---------- ---------- ----------
(Based on Standard & Poor's Ratings as of April 5, 2004)
Investment grade............................................ $ (15,166) $ 67,206 $ 14,620 $ (28,313) $ 38,347
Non-investment grade........................................ 50,260 27,842 -- -- 78,102
No external ratings......................................... (6,894) (727) (346) -- (7,967)
---------- ---------- ---------- ---------- ----------
Total fair value......................................... $ 28,200 $ 94,321 $ 14,274 $ (28,313) $ 108,482
========== ========== ========== ========== ==========
The fair value of outstanding derivative commodity instruments and the fair
value that would be expected after a 10% adverse price change are shown in the
table below (in thousands):
Fair Value
After 10%
Adverse
Fair Value Price Change
----------- -------------
At March 31, 2004:
Electricity.................... $ (78,424) $ (213,771)
Natural gas.................... 186,906 110,683
----------- ------------
Total....................... $ 108,482 $ (103,088)
=========== ============
Derivative commodity instruments included in the table are those included
in Note 9 of the Notes to Consolidated Condensed Financial Statements. The fair
value of derivative commodity instruments included in the table is based on
present value adjusted quoted market prices of comparable contracts. The fair
value of electricity derivative commodity instruments after a 10% adverse price
change includes the effect of increased power prices versus our derivative
forward commitments. Conversely, the fair value of the natural gas derivatives
after a 10% adverse price change reflects a general decline in gas prices versus
our derivative forward commitments. Derivative commodity instruments offset the
price risk exposure of our physical assets. None of the offsetting physical
positions are included in the table above.
Price changes were calculated by assuming an across-the-board ten percent
adverse price change regardless of term or historical relationship between the
contract price of an instrument and the underlying commodity price. In the event
of an actual ten percent change in prices, the fair value of our derivative
portfolio would typically change by more than ten percent for earlier forward
months and less than ten percent for later forward months because of the higher
volatilities in the near term and the effects of discounting expected future
cash flows.
The primary factors affecting the fair value of our derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and MWh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions increased 91%
from December 31, 2003, to March 31, 2004, while the total volume of open power
-54-
derivative positions decreased 20% for the same period. In that prices for
electricity and natural gas are among the most volatile of all commodity prices,
there may be material changes in the fair value of our derivatives over time,
driven both by price volatility and the changes in volume of open derivative
transactions. Under SFAS No. 133, the change since the last balance sheet date
in the total value of the derivatives (both assets and liabilities) is reflected
either in Other Comprehensive Income ("OCI"), net of tax, or in the statement of
operations as an item (gain or loss) of current earnings. As of March 31, 2004,
the majority 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, 2004, have reflected this. See Note 9 of the Notes to Consolidated Condensed
Financial Statements for additional information on derivative activity and OCI.
Collateral Debt Securities -- In connection with the decision of the
Calpine Power Income Fund ("CPIF") to acquire the King City Power Plant and
become the lessor of the facility, we intend to sell certain investments
previously accounted for as held-to-maturity. As of March 31, 2004, the
securities are classified as available-for-sale and recorded at fair market
value in Other Current Assets. The following table presents the face value of
our different classes of collateral debt securities by expected maturity date as
of March 31, 2004, (dollars in thousands):
Weighted
Average
Interest
Rate 2004 2005 2006 2007 2008 Thereafter Total
--------- --------- -------- -------- -------- -------- ---------- ----------
Corporate Debt Securities........... 7.3% $ 4,575 $ 7,825 $ -- $ -- $ -- $ -- $ 12,400
U.S. Treasury Notes................. 6.5% -- 1,975 -- -- -- -- 1,975
U.S. Treasury Securities
(non-interest bearing)............ -- -- -- 9,700 9,100 9,050 87,100 114,950
-------- -------- -------- -------- -------- --------- ----------
Total............................ $ 4,575 $ 9,800 $ 9,700 $ 9,100 $ 9,050 $ 87,100 $ 129,325
======== ======== ======== ======== ======== ========= ==========
The following table presents the fair value of our collateral debt
securities as of March 31, 2004, (dollars in thousands):
Fair Value
----------
Corporate Debt Securities............................. $ 12,854
U.S. Treasury Notes................................... 2,115
U.S. Treasury Securities (non-interest bearing)....... 85,352
----------
Total.............................................. $ 100,321
==========
Interest Rate Swaps and Cross Currency Swaps -- From time to time, we use
interest rate swap and cross currency swap agreements to mitigate our exposure
to interest rate and currency fluctuations associated with certain of our debt
instruments. We do not use interest rate swap and currency swap agreements for
speculative or trading purposes. The following tables summarize the fair market
values of our existing interest rate swap and currency swap agreements as of
March 31, 2004, (dollars in thousands):
Variable to fixed Swaps
Weighted Average Weighted Average
Notional Interest Rate Interest Rate Fair Market
Maturity Date Principal Amount (Pay) (Receive) Value
------------- ---------------- ----------------- ----------------------- ------------
2007........... $ 38,000 3.8% 3-month US $LIBOR $ (1,307)
2007........... 38,333 3.8% 3-month US $LIBOR (1,318)
2007........... 38,667 3.8% 3-month US $LIBOR (1,330)
2011........... 41,879 6.9% 3-month US $LIBOR (6,332)
2012........... 109,998 6.5% 3-month US $LIBOR (17,293)
2014........... 58,682 6.7% 3-month US $LIBOR (8,599)
2016........... 21,750 7.3% 3-month US $LIBOR (4,807)
2016........... 14,500 7.3% 3-month US $LIBOR (3,204)
2016........... 43,500 7.3% 3-month US $LIBOR (9,613)
2016........... 29,000 7.3% 3-month US $LIBOR (6,409)
2016........... 36,250 6.7% 3-month US $LIBOR (8,011)
----------- --- -----------
Total....... $ 470,559 6.1% $ (68,223)
=========== === ===========
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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% $ (3,716)
2011........... 100,000 6-month US $LIBOR 8.5% (1,861)
2011........... 200,000 6-month US $LIBOR 8.5% (4,091)
2018........... 106,000 3-month US $LIBOR 4.0% 96
----------- --- -----------
Total....... $ 506,000 7.6% $ (9,572)
=========== === ===========
Debt Financing -- Because of the significant capital requirements within
our industry, debt financing is often needed to fund our growth. Certain debt
instruments may affect us adversely because of changes in market conditions. We
have used two primary forms of debt which are subject to market risk: (1)
Variable rate construction/project financing and (2) Other variable-rate
instruments. Significant LIBOR increases could have a negative impact on our
future interest expense. Our variable-rate construction/project financing is
primarily through CalGen. Borrowings under this credit agreement are used
exclusively to fund the construction of our power plants. Other variable-rate
instruments consist primarily of our revolving credit and term loan facilities,
which are used for general corporate purposes. Both our variable-rate
construction/project financing and other variable-rate instruments are indexed
to base rates, generally LIBOR, as shown below.
The following table summarizes our variable-rate debt exposed to interest
rate risk as of March 31, 2004. All outstanding balances and fair market values
are shown net of applicable premium or discount, if any (dollars in thousands):
Outstanding Fair Market
Balance Interest Rate Basis(4) Value
------------- ----------------------- -------------
Variable-rate construction/project financing and other variable-rate
instruments:
Short-term
First Priority Senior Secured Term Loan B Notes Due 2007.......... $ 2,000 3-month US $LIBOR $ 2,000
First Priority Secured Institutional Term Loan Due 2009
(CCFC I)........................................................ 3,208 (1) 3,208
Second Priority Senior Secured Term Loan B Notes Due 2007......... 7,500 (2) 7,500
Second Priority Senior Secured Floating Rate Notes Due 2007....... 5,000 (3) 5,000
Riverside Energy Center project financing......................... 5,822 2-month US $LIBOR 5,822
Rocky Mountain Energy Center project financing.................... 3,863 1-month US $LIBOR 3,863
MEP Pleasant Hill Term Loan, Tranche A............................ 4,803 3-month US $LIBOR 4,803
------------- -------------
Total short-term.............................................. $ 32,196 $ 32,196
============= =============
Long-term
Blue Spruce Energy Center Project Financing....................... $ 140,000 (3) $ 140,000
Riverside Energy Center Project Financing......................... 178,831 3-month US $LIBOR 178,831
MEP Pleasant Hill Term Loan, Tranche A............................ 125,430 3-month US $LIBOR 125,430
Rocky Mountain Energy Center Project Financing.................... 177,331 1-month US $LIBOR 177,331
First Priority Secured Institutional Term Loan Due 2009
(CCFC I)........................................................ 376,418 (1) 376,418
Second Priority Senior Secured Floating Rate Notes Due 2011
(CCFC I)........................................................ 407,840 (1) 407,840
Corporate revolving line of credit................................ -- 1-month US $LIBOR --
Thomassen revolving line of credit................................ -- 1-month EURIBOR --
First Priority Senior Secured Term Loan B Notes Due 2007.......... 197,000 3-month US $LIBOR 197,000
Second Priority Senior Secured Floating Rate Notes Due 2007....... 492,500 (3) 492,500
Second Priority Senior Secured Term Loan B Notes Due 2007......... 738,750 (2) 738,750
First Priority Secured Floating Rate Notes Due 2009 (CalGen)...... 235,000 1-month US $LIBOR 235,000
First Priority Secured Term Loans Due 2009 (CalGen)............... 600,000 (5) 600,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen)..... 630,439 (5) 630,439
Second Priority Secured Term Loans Due 2010 (CalGen).............. 98,506 (5) 98,506
Third Priority Secured Floating Rate Notes Due 2011 (CalGen)...... 680,000 6-month US $LIBOR 680,000
------------- -------------
Total long-term................................................ $ 5,078,045 $ 5,078,045
============= =============
Total variable-rate construction/project financing and
other variable-rate instruments............................ $ 5,110,241 $ 5,110,241
============= =============
- ----------
<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.
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(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.
</FN>
Construction/project financing facility -- In November 2004 the $2.5
billion secured construction financing revolving facility for our wholly owned
subsidiary CCFC II (or CalGen) was scheduled to mature. On March 23, 2004,
CalGen completed its offering of secured institutional term loans and secured
notes, which refinanced the CalGen facility. We realized total proceeds from the
offering in the amount of $2.4 billion, before transaction costs and fees. See
Note 6 of the Notes to Consolidated Condensed Financial Statements for more
information regarding this offering.
On February 20, 2004, we completed a $250.0 million, non-recourse project
financing for the 600-megawatt Rocky Mountain Energy Center. A consortium of
banks financed the construction of the plant at a rate of LIBOR plus 250 basis
points. Upon commercial operation of the Rocky Mountain Energy Center in the
summer of 2004, the banks will provide a three-year term-loan facility.
On March 26, 2004, we acquired the remaining 50% interest in the Aries
facility from a subsidiary of Aquila, Inc. (Aquila and its subsidiaries referred
to collectively as "Aquila"). At the same time, Aries terminated a tolling
contract with another subsidiary of Aquila. Aquila paid $5 million in cash and
assigned to us certain transmission and other rights. Aquila and Calpine also
amended a master netting agreement between them, and as a result, we returned
cash margin deposits totaling $10.8 million to Aquila. Contemporaneous with the
closing of the acquisition, Aries' existing construction loan was converted to
two term loans totaling $178.8 million, of which $130.2 is variable-rate debt.
We contributed $15 million of equity to Aries in connection with the term out of
the construction loan.
New Accounting Pronouncements
On January 1, 2003, we prospectively adopted the fair value method of
accounting for stock-based employee compensation pursuant to SFAS No. 123,
"Accounting for Stock-Based Compensation" as amended by SFAS No. 148,
"Accounting for Stock-Based Compensation -- Transition and Disclosure." SFAS No.
148 amends SFAS No. 123 to provide alternative methods of transition for
companies that voluntarily change their accounting for stock-based compensation
from the less preferred intrinsic value based method to the more preferred fair
value based method. Prior to its amendment, SFAS No. 123 required that companies
enacting a voluntary change in accounting principle from the intrinsic value
methodology provided by Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees" could only do so on a prospective
basis; no adoption or transition provisions were established to allow for a
restatement of prior period financial statements. SFAS No. 148 provides two
additional transition options to report the change in accounting principle --
the modified prospective method and the retroactive restatement method.
Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. We elected to adopt the
provisions of SFAS No. 123 on a prospective basis; consequently, we are required
to provide a pro-forma disclosure of net income and earnings per share as if
SFAS No. 123 accounting had been applied to all prior periods presented within
its financial statements. See Note 2 of the Notes to Consolidated Condensed
Financial Statements for more information.
In January 2003 FASB issued FIN 46. FIN 46 requires the consolidation of an
entity by an enterprise that absorbs a majority of the entity's expected losses,
receives a majority of the entity's expected residual returns, or both, as a
result of ownership, contractual or other financial interest in the entity.
Historically, entities have generally been consolidated by an enterprise when it
has a controlling financial interest through ownership of a majority voting
interest in the entity. The objectives of FIN 46 are to provide guidance on the
identification of Variable Interest Entities ("VIEs") for which control is
achieved through means other than ownership of a majority of the voting interest
of the entity, and how to determine which business enterprise (if any), as the
Primary Beneficiary, should consolidate the Variable Interest Entity ("VIE").
This new model for consolidation applies to an entity in which either (1) the
at-risk equity is insufficient to absorb expected losses without additional
subordinated financial support or (2) its at-risk equity holders as a group are
not able to make decisions that have a significant impact on the success or
failure of the entity's ongoing activities. A variable interest in a VIE, by
definition, is an asset, liability, equity, contractual arrangement or other
economic interest that absorbs the entity's variability.
In December 2003 FASB modified FIN 46 with FIN 46-R to make certain
technical corrections and to address certain implementation issues. FIN 46, as
originally issued, was effective immediately for VIEs created or acquired after
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January 31, 2003. FIN 46-R delayed the effective date of the interpretation to
no later than March 31, 2004, (for calendar-year enterprises), except for
Special Purpose Entities ("SPEs") for which the effective date was December 31,
2003. We have adopted FIN 46-R for our investment in SPEs, equity method joint
ventures, our wholly owned subsidiaries that are subject to long-term power
purchase agreements and tolling arrangements, operating lease arrangements
containing fixed price purchase options and our wholly owned subsidiaries that
have issued mandatorily redeemable non-controlling preferred interests.
We evaluated our investments in joint ventures and operating lease
arrangements containing fixed price purchase options and concluded that, in some
instances, these entities were VIEs. However,in these instances, we were not the
Primary Beneficiary, as we would not absorb a majority of these entities'
expected variability. The fixed price purchase options under our operating lease
arrangements were not considered significant variable interests. However, our
investments in joint ventures were considered significant. See Note 7 of the
Notes to Consolidated Condensed Financial Statements for more information
related to these joint venture investments.
An analysis was performed for 100% Company-owned subsidiaries with
significant long-term power sales or tolling agreements. Certain of the 100%
Company-owned subsidiaries were deemed to be VIEs by virtue of a power sales or
tolling agreement which was longer than 10 years and for more than 50% of the
entity's capacity. However, in all cases, we absorbed a majority of the entity's
variability and continue to consolidate these 100% Company-owned subsidiaries.
We qualitatively determined that power sales or tolling agreements less than 10
years in length and for less than 50% of the entity's capacity would not cause
the power purchaser to be the Primary Beneficiary, due to the length of the
economic life of the underlying assets. Also, power sales and tolling agreements
meeting the definition of a lease under EITF Issue No. 01-08, "Determining
Whether an Arrangement Contains a Lease," were not considered variable
interests, because payments under these leasing arrangements create rather than
absorb the entity's variability.
A similar analysis was performed for our wholly owned subsidiaries that
have issued mandatorily redeemable non-controlling preferred interests. These
entities were determined to be VIEs in which we absorb the majority of the
variability, primarily due to the debt characteristics of the preferred
interest, which are classified as debt in accordance with SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity" in our Consolidated Condensed Balance Sheets.
Consequently, we continue to consolidate these wholly owned subsidiaries. See
Note 2 of the Notes to Consolidated Condensed Financial Statements for more
information.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in Item 2.
Item 4. Controls and Procedures.
The Company's Chief Executive Officer and Chief Financial Officer, based on
the evaluation of the Company's disclosure controls and procedures (as defined
in Rules 13a-15(e) and 15d-15(e) of the Securities and Exchange Act of 1934, as
amended) required by paragraph (b) of Rule 13a-15 or Rule 15d-15, as of March
31, 2004, have concluded that the Company's disclosure controls and procedures
were effective to ensure the timely collection, evaluation and disclosure of
information relating to the Company that would potentially be subject to
disclosure under the Securities Exchange Act of 1934, as amended, and the rules
and regulations promulgated thereunder with the exception of the deficiencies
noted below.
As reported in our Form 10-K filing for 2003, in connection with the audit
of our Consolidated Financial Statements for the fiscal year ended December 31,
2003, our independent auditors reviewed our information systems control
framework and identified to us certain significant deficiencies in the design of
such systems. These design deficiencies generally related to the number of
persons having access to certain of our information systems databases, as well
as the segregation of duties of persons with such access. The Company concluded
that, in the aggregate, these deficiencies constituted a material control
weakness, and the Company performed substantial analytical and post-closing
procedures as a result of these design deficiencies. Based on the Company's
compensating controls and testing, we concluded that these design deficiencies
did not result in any material errors in our financial statements as of December
31, 2003. Additionally, during the quarter ended March 31, 2004, we completed
the process of correcting these design deficiencies and are in the process of
testing the effectiveness of these changes. Other than correcting the material
control weakness identified above, there were no other changes in the Company's
internal controls over financial reporting identified in connection with the
evaluation required by paragraph (d) of the Rule 13a-15 or Rule 15d-15 that have
materially affected, or are reasonably likely to materially affect, the internal
controls over financial reporting.
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PART II -- OTHER INFORMATION
Item 1. Legal Proceedings.
We are party to various litigation matters arising out of the normal course
of business, the more significant of which are summarized below. The ultimate
outcome of each of these matters cannot presently be determined, nor can the
liability that could potentially result from a negative outcome be reasonably
estimated presently for every case. The liability we may ultimately incur with
respect to any one of these matters in the event of a negative outcome may be in
excess of amounts currently accrued with respect to such matters and, as a
result of these matters, may potentially be material to our Consolidated
Condensed Financial Statements.
Securities Class Action Lawsuits. Since March 11, 2002, fourteen
shareholder lawsuits have been filed against Calpine and certain of its officers
in the United States District Court for the Northern District of California. The
actions captioned Weisz v. Calpine Corp., et al., filed March 11, 2002, and
Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002, are
purported class actions on behalf of purchasers of Calpine stock between March
15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18,
2002, is a purported class action on behalf of purchasers of Calpine stock
between February 6, 2001 and December 13, 2001. The eleven other actions,
captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v.
Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local
1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta
v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp., and Rose v.
Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The
complaints in these eleven actions are virtually identical-- they are filed by
three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of Calpine's
securities between January 5, 2001 and December 13, 2001.
The complaints in these fourteen actions allege that, during the purported
class periods, certain Calpine executives issued false and misleading statements
about Calpine's financial condition in violation of Sections 10(b) and 20(1) of
the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek
an unspecified amount of damages, in addition to other forms of relief.
In addition, a fifteenth securities class action, Ser v. Calpine, et al.,
was filed on May 13, 2002. The underlying allegations in the Ser action are
substantially the same as those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of Calpine's
8.5% Senior Notes Due February 15, 2011 ("2011 Notes") and the alleged class
period is October 15, 2001 through December 13, 2001. The Ser complaint alleges
that, in violation of Sections 11 and 15 of the Securities Act of 1933, the
Supplemental Prospectus for the 2011 Notes contained false and misleading
statements regarding Calpine's financial condition. This action names Calpine,
certain of its officers and directors, and the underwriters of the 2011 Notes
offering as defendants, and seeks an unspecified amount of damages, in addition
to other forms of relief.
All fifteen of these securities class action lawsuits were consolidated in
the United States District Court for the Northern District of California.
Plaintiffs filed a first amended complaint in October 2002. The amended
complaint did not include the 1933 Act complaints raised in the bondholders'
complaint, and the number of defendants named was reduced. On January 16, 2003,
before our response was due to this amended complaint, plaintiffs filed a
further second complaint. This second amended complaint added three additional
Calpine executives and Arthur Andersen LLP as defendants. The second amended
complaint set forth additional alleged violations of Section 10 of the
Securities Exchange Act of 1934 relating to allegedly false and misleading
statements made regarding Calpine's role in the California energy crisis, the
long term power contracts with the California Department of Water Resources, and
Calpine's dealings with Enron, and additional claims under Section 11 and
Section 15 of the Securities Act of 1933 relating to statements regarding the
causes of the California energy crisis. We filed a motion to dismiss this
consolidated action in early April 2003.
On August 29, 2003, the judge issued an order dismissing, with leave to
amend, all of the allegations set forth in the second amended complaint except
for a claim under Section 11 of the Securities Act relating to statements
relating to the causes of the California energy crisis and the related increase
in wholesale prices contained in the Supplemental Prospectuses for the 2011
Notes.
The judge instructed plaintiff, Julies Ser, to file a third amended
complaint, which he did on October 17, 2003. The third amended complaint names
Calpine and three executives as defendants and alleges the Section 11 claim that
survived the judge's August 29, 2003 order.
On November 21, 2003, Calpine and the individual defendants moved
to dismiss the third amended complaint on the grounds that plaintiff's
Section 11 claim was barred by the applicable one-year statute of limitations.
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On February 4, 2004, the judge denied our motion to dismiss but has asked the
parties to be prepared to file summary judgment motions to address the statute
of limitations issue. We filed our answer to the third amended complaint on
February 28, 2004.
In a separate order dated February 4, 2004, the court denied without
prejudice Julies Ser's motion to be appointed lead plaintiff. Mr. Ser
subsequently stated he no longer desired to serve as lead plaintiff. On April 4,
2004, the Policemen and Firemen Retirement System of the City of Detroit ("P&F")
moved to be appointed lead plaintiff. Calpine filed a response in opposition to
this motion. The court has scheduled a hearing on this matter for May 11, 2004.
We consider the lawsuit to be without merit and we intend to continue to
defend vigorously against these allegations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities
class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was
filed on March 11, 2003, against Calpine, its directors and certain investment
banks in state superior court of San Diego County, California. The underlying
allegations in the Hawaii Structural Ironworkers Pension Fund action ("Hawaii
action") are substantially the same as the federal securities class actions
described above. However, the Hawaii action is brought on behalf of a purported
class of purchasers of Calpine's equity securities sold to public investors in
its April 2002 equity offering. The Hawaii action alleges that the Registration
Statement and Prospectus filed by Calpine which became effective on April 24,
2002, contained false and misleading statements regarding Calpine's financial
condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933.
The Hawaii action relies in part on Calpine's restatement of certain past
financial results, announced on March 3, 2003, to support its allegations. The
Hawaii action seeks an unspecified amount of damages, in addition to other forms
of relief.
We removed the Hawaii action to federal court in April 2003 and filed a
motion to transfer the case for consolidation with the other securities class
action lawsuits in the United States District Court for the Northern District of
California in May 2003. Plaintiff sought to have the action remanded to state
court, and on August 27, 2003, the United States District Court for the Southern
District of California granted plaintiff's motion to remand the action to state
court. In early October 2003 plaintiff agreed to dismiss the claims it has
against three of the outside directors.
On November 5, 2003, Calpine, the individual defendants and the underwriter
defendants filed motions to dismiss this complaint on numerous grounds. On
February 6, 2004, the court issued a tentative ruling sustaining our motion to
dismiss on the issue of plaintiff's standing. The court found that plaintiff had
not shown that it had purchased Calpine stock "traceable" to the April 2002
equity offering. The court overruled our motion to dismiss on all other grounds.
On March 12, 2004, after oral argument on the issues, the court confirmed its
February 2, 2004, ruling.
On February 20, 2004, plaintiff filed an amended complaint, and in late
March 2004 Calpine and the individual defendants filed answers to this
complaint. On April 9, 2004, we and the individual defendants filed motions to
transfer the lawsuit to Santa Clara County Superior Court, which motions were
granted on May 7, 2004. We consider this lawsuit to be without merit and intend
to continue to defend vigorously against it.
Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in
the Calpine Corporation Retirement Savings Plan (the "401(k) Plan") filed a
class action lawsuit in the United States District Court for the Northern
District of California. The underlying allegations in this action ("Phelps
action") are substantially the same as those in the securities class actions
described above. However, the Phelps action is brought on behalf of a purported
class of participants in the 401(k) Plan. The Phelps action alleges that various
filings and statements made by Calpine during the class period were materially
false and misleading, and that defendants failed to fulfill their fiduciary
obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to
invest in Calpine common stock. The Phelps action seeks an unspecified amount of
damages, in addition to other forms of relief. In May 2003 Lennette Poor-Herena,
another participant in the 401(k) Plan, filed a substantially similar class
action lawsuit as the Phelps action also in the Northern District of California.
Plaintiffs' counsel is the same in both of these actions, and they have agreed
to consolidate these two cases and to coordinate them with the consolidated
federal securities class actions described above. On January 20, 2004, plaintiff
James Phelps filed a consolidated ERISA complaint naming Calpine and numerous
individual current and former Calpine Board members and employees as defendants.
Pursuant to a stipulated agreement with plaintiff, Calpine's response to the
amended complaint is due June 18, 2004. We consider this lawsuit to be without
merit and intend to vigorously defend against it.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of Calpine against its directors and one of
its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. and
is pending in state superior court of Santa Clara County, California. Calpine is
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a nominal defendant in this lawsuit, which alleges claims relating to
purportedly misleading statements about Calpine and stock sales by certain of
the director defendants and the officer defendant. In December 2002 the court
dismissed the complaint with respect to certain of the director defendants for
lack of personal jurisdiction, though plaintiff may appeal this ruling. In early
February 2003 plaintiff filed an amended complaint. In March 2003 Calpine and
the individual defendants filed motions to dismiss and motions to stay this
proceeding in favor of the federal securities class actions described above. In
July 2003 the court granted the motions to stay this proceeding in favor of the
consolidated federal securities class actions described above. We cannot
estimate the possible loss or range of possible loss from this matter. We
consider this lawsuit to be without merit and intend to vigorously defend
against it.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District of
California on behalf of Calpine against its directors, captioned Gordon v.
Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003 plaintiff agreed to stay these proceedings in
favor of the consolidated federal securities class action described above and to
dismiss without prejudice certain director defendants. On March 4, 2003,
plaintiff filed papers with the court voluntarily agreeing to dismiss without
prejudice the claims he had against three of the outside directors. We cannot
estimate the possible loss or range of possible loss from this matter. We
consider this lawsuit to be without merit and intend to continue to defend
vigorously against it.
Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, Calpine
sued Automated Credit Exchange ("ACE") in state superior court of Alameda
County, California for negligence and breach of contract to recover reclaim
trading credits, a form of emission reduction credits that should have been held
in Calpine's account with U.S. Trust Company ("US Trust"). Calpine wrote off
$17.7 million in December 2001 related to losses that it alleged were caused by
ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002,
pursuant to which ACE made a payment to Calpine of $7 million and transferred to
Calpine the rights to the emission reduction credits to be held by ACE. We
recognized the $7 million as income in the second quarter of 2002. In June 2002
a complaint was filed by InterGen North America, L.P. ("InterGen") against Anne
M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity,
which filed for bankruptcy protection on May 6, 2002. InterGen alleges it
suffered a loss of emission reduction credits from EonXchange in a manner
similar to Calpine's loss from ACE. InterGen's complaint alleges that Anne
Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and
that ACE and other Sholtz entities should be deemed to be one economic
enterprise and all retroactively included in the EonXchange bankruptcy filing as
of May 6, 2002. By a judgment entered on October 30, 2002, the bankruptcy court
consolidated ACE and the other Sholtz controlled entities with the bankruptcy
estate of EonXchange. Subsequently, the Trustee of EonXchange filed a separate
motion to substantively consolidate Anne Sholtz into the bankruptcy estate of
EonXchange. Although Anne Sholtz initially opposed such motion, she entered into
a settlement agreement with the Trustee consenting to her being substantively
consolidated into the bankruptcy proceeding. The bankruptcy court entered an
order approving Anne Sholtz's settlement agreement with the Trustee on April 3,
2002. On July 10, 2003, Howard Grobstein, the Trustee in the EonXchange
bankruptcy, filed a complaint for avoidance against Calpine, seeking recovery of
the $7 million (plus interest and costs) paid to Calpine in the March 29, 2002
Settlement Agreement. The complaint claims that the $7 million received by
Calpine in the Settlement Agreement was transferred within 90 days of the filing
of bankruptcy and therefore should be avoided and preserved for the benefit of
the bankruptcy estate. On August 28, 2003, Calpine filed its answer denying that
the $7 million is an avoidable preference. On January 26, 2004, Calpine filed a
motion for partial summary judgment asserting that the bankruptcy court did not
properly consolidate Anne Sholtz into the bankruptcy estate of EonXchange. If
the motion is granted, at least $2.9 million of the $7 million that the Trustee
is seeking to recover from Calpine could not be avoided as a preferential
transfer. In response, the Trustee filed a motion for summary judgment for the
entire $7 million plus interest against Calpine. Although Calpine will assert
various defenses to the claims asserted by the Trustee, Calpine and the Trustee
have entered into stipulations to continue the various hearing dates on the
pending motions for summary judgment in order to pursue settlement discussions.
We believe we have adequately reserved for the possible loss, if any, we may
ultimately incur as a result of this matter.
International Paper Company v. Androscoggin Energy LLC. In October 2000
International Paper Company ("IP") filed a complaint in the United States
District Court for the Northern District of Illinois against Androscoggin Energy
LLC ("AELLC") alleging that AELLC breached certain contractual representations
and warranties by failing to disclose facts surrounding the termination,
effective May 8, 1998, of one of AELLC's fixed-cost gas supply agreements. We
had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which
closed in October 2000. AELLC filed a counterclaim against IP that has been
referred to arbitration that AELLC may commence at its discretion upon further
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evaluation. On November 7, 2002, the court issued an opinion on the parties'
cross motions for summary judgment finding in AELLC's favor on certain matters
though granting summary judgment to IP on the liability aspect of a particular
claim against AELLC. The court also denied a motion submitted by IP for
preliminary injunction to permit IP to make payment of funds into escrow (not
directly to AELLC) and require AELLC to post a significant bond.
In mid-April of 2003 IP unilaterally availed itself to self-help in
withholding amounts in excess of $2.0 million as a set-off for litigation
expenses and fees incurred to date as well as an estimated portion of a rate
fund to AELLC. Upon AELLC's amended complaint and request for immediate
injunctive relief against such actions, the court ordered that IP must pay the
approximately $1.2 million withheld as attorneys' fees related to the litigation
as any such perceived entitlement was premature, but deferred to provide
injunctive relief on the incomplete record concerning the offset of $799,000 as
an estimated pass-through of the rate fund. IP complied with the order on April
29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On
June 26, 2003, the court entered an order dismissing AELLC's amended
counterclaim without prejudice to AELLC refiling the claims as breach of
contract claims in a separate lawsuit. On December 11, 2003, the court denied in
part IP's summary judgment motion pertaining to damages. In short, the court:
(i) determined that, as a matter of law, IP is entitled to pursue an action for
damages as a result of AELLC's breach, and (ii) ruled that sufficient questions
of fact remain to deny IP summary judgment on the measure of damages as IP did
not sufficiently establish causation resulting from AELLC's breach of contract
(the liability aspect of which IP obtained a summary judgment in December 2002).
On February 2, 2004, the parties filed a Final Pretrial Order with the court.
The case appears likely scheduled for trial in the second quarter of 2004,
subject to the court's discretion and calendar. We believe we have adequately
reserved for the possible loss, if any, we may ultimately incur as a result of
this matter.
Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22,
2003, Pacific Gas and Electric Company ("PG&E") filed with the California Public
Utilities Commission ("CPUC") a Complaint of PG&E and Request for Immediate
Issuance of an Order to Show Cause ("complaint") against Calpine Corporation,
CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas
Company, and Lodi Gas Storage, LLC ("LGS"). The complaint requests the CPUC to
issue an order requiring defendants to show cause why they should not be ordered
to cease and desist from using any direct interconnections between the
facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek
and obtain regulatory approval from the CPUC. The complaint also seeks an order
directing defendants to pay to PG&E any underpayments of PG&E's tariffed
transportation rates and to make restitution for any profits earned from any
business activity related to LGS' direct interconnections to any entity other
than PG&E. The complaint further alleges that various natural gas consumers,
including Calpine affiliated generation projects within California, are engaged
with defendants in the acts complained of, and that the defendants unlawfully
bypass PG&E's system and operate as an unregulated local distribution company
within PG&E's service territory. On August 27, 2003, Calpine filed its answer
and a motion to dismiss. LGS also made similar filings. On October 16, 2003, the
presiding administrative law judge denied the motion to dismiss and on October
24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule
and set the matter for an evidentiary hearing. On January 15, 2004, Calpine, LGS
and PG&E executed a Settlement Agreement to resolve all outstanding allegations
and claims raised in the complaint. Certain aspects of the Settlement Agreement
are effective immediately and the effectiveness of other provisions is subject
to the approval of the Settlement Agreement by the CPUC. In the event the CPUC
fails to approve the Settlement Agreement, its operative terms and conditions
become null and void. The Settlement Agreement provides, in part, for: 1) PG&E
to be paid $2.7 million; 2) the disconnection of the LGS interconnections with
Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental
approval before resuming any sales or exchanges at the Ryer Island Meter
Station; 4) PG&E's withdrawal of its public utility claims against Calpine; and
5) no party admitting any wrongdoing. Accordingly, the presiding administrative
law judge vacated the hearing schedule and established a new procedural schedule
for the filing of the Settlement Agreement. On February 6, 2004, the Settlement
Agreement was filed with the CPUC. The parties were given the opportunity to
submit comments and reply comments on the Settlement Agreement. The matter is
currently pending and shall be considered by the CPUC following the issuance of
a recommendation by the presiding administrative law judge.
Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On
November 5, 2003, Panda Energy International, Inc. and certain related parties,
including PLC II, LLC, (collectively "Panda") filed suit against Calpine and
certain of its affiliates in the United States District Court for the Northern
District of Texas, alleging, among other things, that we breached duties of care
and loyalty allegedly owed to Panda by failing to correctly construct and
operate the Oneta Energy Center ("Oneta"), which we acquired from Panda, in
accordance with Panda's original plans. Panda alleges that it is entitled to a
portion of the profits from Oneta plant and that Calpine's actions have reduced
the profits from Oneta plant thereby undermining Panda's ability to repay monies
owed to Calpine on December 1, 2003, under a promissory note on which
approximately $38.6 million (including interest) is currently outstanding and
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past due. The note is collateralized by Panda's carried interest in the income
generated from Oneta, which achieved full commercial operations in June 2003. We
have filed a counterclaim against Panda Energy International, Inc. (and PLC II,
LLC) based on a guaranty, and have also filed a motion to dismiss as to the
causes of action alleging federal and state securities laws violations. The
motion to dismiss is currently pending before the court. However, at the present
time, we cannot estimate the potential loss, if any, that might arise from this
matter. We consider Panda's lawsuit to be without merit and intend to defend
vigorously against it. We stopped accruing interest income on the promissory
note due December 1, 2003, as of the due date because of Panda's default in
repayment of the note.
California Business & Professions Code Section 17200 Cases, of which the
lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C.,
et al. This purported class action complaint filed in May 2002 against twenty
energy traders and energy companies, including CES, alleges that defendants
exercised market power and manipulated prices in violation of California
Business & Professions Code Section 17200 et seq., and seeks injunctive relief,
restitution, and attorneys' fees. We also have been named in seven other similar
complaints for violations of Section 17200. All seven cases were removed from
the various state courts in which they were originally filed to federal court
for pretrial proceedings with other cases in which we are not named as a
defendant. However, at the present time, we cannot estimate the potential loss,
if any, that might arise from this matter. We consider the allegations to be
without merit, and filed a motion to dismiss on August 28, 2003. The court
granted the motion, and plaintiffs have appealed.
Prior to the motion to dismiss being granted, one of the actions, captioned
Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to state
superior court of Alameda County, California. On January 12, 2004, CES was added
as a defendant in Millar. This action includes similar allegations to the other
17200 cases, but also seeks rescission of the long-term power contracts with the
California Department of Water Resources.
Upon motion from another newly added defendant, Millar was recently removed
to federal court. It has now been transferred to the same judge that is
presiding over the other 17200 cases described above, where it will be
consolidated with such cases for pretrial purposes. We anticipate filing a
timely motion for dismissal of Millar as well.
Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy
Services, L.P. before the FERC, filed on December 4, 2001. Nevada Section 206
Complaint. On December 4, 2001, Nevada Power Company ("NPC") and Sierra Pacific
Power Company ("SPPC") filed a complaint with FERC under Section 206 of the
Federal Power Act against a number of parties to their power sales agreements,
including Calpine. NPC and SPPC allege in their complaint, which seeks a refund,
that the prices they agreed to pay in certain of the power sales agreements,
including those signed with Calpine, were negotiated during a time when the
power market was dysfunctional and that they are unjust and unreasonable. The
administrative law judge issued an Initial Decision on December 19, 2002, that
found for Calpine and the other respondents in the case and denied NPC the
relief that it was seeking. In June 2003, FERC rejected the complaint. Some
plaintiffs appealed to the FERC and their request for rehearing was denied. The
FERC decision is therefore final, and the matter is pending on appeal before the
United States Court of Appeals for the Ninth Circuit.
Transmission Service Agreement with Nevada Power. On March 16, 2004, NPC
filed a petition for declaratory order at FERC (Docket No. EL04-90-000) asking
that an order be issued requiring Calpine and Reliant Energy Services, Inc. to
pay for transmission service under their Transmission Service Agreements
("TSAs") with NPC or, if the TSAs are terminated, to pay the lesser of the
transmission charges or a pro rata share of the total cost of NPC's Centennial
Project (approximately $33 million for Calpine). Calpine had previously provided
security to NPC for these costs in the form of a surety bond issued by Fireman's
Fund Insurance Company ("FFIC"). The Centennial Project involves construction of
various transmission facilities in two phases; Calpine's Moapa Energy Center
("MEC") is scheduled to receive service under its TSA from facilities yet to be
constructed in the second phase of the Centennial Project. Calpine has filed a
protest to the petition asserting that Calpine will take service under the TSA
if NPC proceeds to execute a purchase power agreement ("PPA") with MEC based on
its winning bid in the Request for Proposals that NPC conducted in 2003. Calpine
also has taken the position that if NPC does not execute a PPA with MEC, it will
terminate the TSA and any payment by Calpine would be limited to a pro rata
allocation of costs incurred to date on the second phase of the project
(approximately $4.5 million in total) among the three customers to be served. At
this time, we are unable to predict the final outcome of this proceeding or its
impact on us.
On or about April 27, 2004, NPC alleged to FFIC that Calpine had defaulted
on the TSA and made demand on FFIC for the full amount of the surety bond,
$33,333,333.00. On April 29, 2004, FFIC filed a complaint for declaratory order
in state superior court of Marin County, California in connection with this
demand.
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FFIC's complaint asks that an order be issued declaring that it has no
obligation to make payment under the bond and, if the court determines that FFIC
does have an obligation to make payment, FFIC asks that an order be issued
declaring that (i) Calpine has an obligation to replace it with funds equal to
the amount of NPC's demand against the bond and (ii) Calpine is obligated to
indemnify and hold FFIC harmless for all loss, costs and fees incurred as a
result of the issuance of the bond. Calpine is preparing to file a response to
the complaint. Calpine's position will be, among other items, that it did not
default on its obligations under the TSA and therefore NPC is not entitled to
make a demand upon the FFIC bond. At this time, we are unable to predict the
outcome of this proceeding or its impact on us.
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002, Calpine Canada Natural Gas Partnership ("Calpine Canada") filed a
complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp.
("Enron Canada") owed it approximately $1.5 million from the sale of gas in
connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron
Canada has not sought bankruptcy relief and has counterclaimed in the amount of
$18 million. Discovery is currently in progress, and we believe that Enron
Canada's counterclaim is without merit and intend to vigorously defend against
it.
Jones v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones
and the Estate of Cynthia Jones filed a complaint against Calpine in the United
States District Court for the Western District of Washington. Calpine purchased
Goldendale Energy, Inc., a Washington corporation, from Darrell Jones. The
agreement provided, among other things, that upon substantial completion of the
Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0
million less $0.2 million per day for each day that elapsed between July 1,
2002, and the date of substantial completion. Substantial completion of the
Goldendale facility has not occurred and the daily reduction in the payment
amount has reduced the $18.0 million payment to zero. The complaint alleges that
by not achieving substantial completion by July 1, 2002, Calpine breached its
contract with Mr. Jones, violated a duty of good faith and fair dealing, and
caused an inequitable forfeiture. The complaint seeks damages in an unspecified
amount in excess of $75,000. On July 28, 2003, Calpine filed a motion to dismiss
the complaint for failure to state a claim upon which relief can be granted. The
court granted Calpine's motion to dismiss the complaint on March 10, 2004.
Plaintiffs have filed a motion for reconsideration of the decision, and the
plaintiffs may also ultimately appeal. Calpine still, however, expects to make
the $6.0 million payment to the estates when the project is completed.
In addition, we are involved in various other claims and legal actions
arising out of the normal course of our business. We do not expect that the
outcome of these proceedings will have a material adverse effect on our
financial position or results of operations.
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities.
Convertible Senior Notes
4% Convertible Senior Notes Due 2006. On December 26, 2001, we completed a
private placement of $1.0 billion aggregate principal amount of our 4%
Convertible Senior Notes Due 2006 ("2006 Convertible Senior Notes"). The initial
purchaser of the 2006 Convertible Senior Notes was Deutsche Bank Alex. Brown
Inc. Deutsche Bank exercised its option to acquire an additional $200.0 million
aggregate principal amount of the 2006 Convertible Senior Notes by purchasing an
additional $100.0 million aggregate principal amount of the 2006 Convertible
Senior Notes on each of December 31, 2001, and January 3, 2002. The offering
price of the 2006 Convertible Senior Notes was 100% of the principal amount,
less an aggregate underwriting discount of $30.0 million. Each sale of the 2006
Convertible Senior Notes to Deutsche Bank was exempt from registration in
reliance on Section 4(2) under the Securities Act of 1933, as amended, as a
transaction not involving a public offering. The 2006 Convertible Senior Notes
were re-offered by Deutsche Bank to qualified institutional buyers in reliance
on Rule 144A under the Securities Act.
We subsequently filed with the SEC a registration statement with respect to
resales of the 2006 Convertible Senior Notes, which was declared effective by
the SEC on June 21, 2002.
The 2006 Convertible Senior Notes are convertible into shares of our common
stock at a conversion price of $18.07 per share which represents a 13.0% premium
over the New York Stock Exchange closing price of $15.99 per share on December
26, 2001. The conversion price is subject to adjustment in certain
circumstances. We have reserved 66,408,411 shares of our authorized common stock
for issuance upon conversion of the 2006 Convertible Senior Notes, which are
convertible at any time on or before the close of business on the day that is
two business days prior to the maturity date, December 26, 2006, unless we have
previously repurchased the 2006 Convertible Senior Notes. Holders of the 2006
Convertible Senior Notes have the right to require us to repurchase their notes
on at par plus accrued interest December 26, 2004. We may choose to pay the
repurchase price in cash or shares of common stock, or a combination thereof.
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During the three months ended March 31, 2004, we repurchased $178.5 million
in principal amount of our outstanding 2006 Convertible Senior Notes that can be
put to us in exchange for $177.5 million in cash. Additionally, on February 9,
2004, we made a cash tender offer, which expired on March 9, 2004, for any and
all of the then still outstanding 2006 Convertible Senior Notes at a price of
par plus accrued interest. On March 10, 2004, we paid an aggregate amount of
$412.8 million for the tendered 2006 Convertible Senior Notes, which included
accrued interest of $3.4 million. At March 31, 2004, 2006 Convertible Senior
Notes in the aggregate principal amount of $72.1 million remain outstanding.
4 3/4% Contingent Convertible Senior Notes Due 2023. On November 17, 2003,
we completed the issuance of $650 million aggregate principal amount of our
43/4% Contingent Convertible Senior Notes Due 2023 ("2023 Convertible Notes").
The initial purchasers of the 2023 Convertible Notes were Deutsche Bank
Securities Inc., Credit Lyonnais Securities (USA) Inc., Harris Nesbitt Corp. and
Williams Capital Group LP (the "initial purchasers"). One of the initial
purchasers, Deutsche Bank Securities Inc., exercised its option to acquire an
additional $250.0 million aggregate principal amount of the 2023 Convertible
Notes on January 9, 2004. The offering price of the 2023 Convertible Notes was
100% of the principal amount of the 2023 Convertible Senior Notes, less an
aggregate underwriting discount of $24.75 million. Each sale of the 2023
Convertible Notes to an initial purchaser was exempt from registration in
reliance on Section 4(2) under the Securities Act of 1933, as amended, as a
transaction not involving a public offering. The 2023 Convertible Notes were
offered by each initial purchaser to qualified institutional buyers in reliance
on Rule 144A under the Securities Act.
Upon the occurrence of certain contingencies, the 2023 Convertible Notes
are convertible, at the option of holder, into cash and shares of our common
stock at an initial conversion price of $6.50 per share, which represents a 38%
premium over The New York Stock Exchange closing price of $4.71 per share on
November 6, 2003. The number of shares of our common stock a holder ultimately
receives upon conversion is determined by a formula based on the closing price
of our common stock on The New York Stock Exchange over a period of five
consecutive trading days during a specified period. We have initially reserved
69,230,000 shares of our authorized common stock for issuance upon conversion of
the 2023 Convertible Notes, and have undertaken to reserve additional shares as
may be necessary to satisfy our obligation to deliver shares upon conversion if
our stock price increases such that the numbers of shares reserved is
inadequate. Upon conversion of the 2023 Convertible Notes, we will deliver par
value in cash and any additional value in shares of our common stock. The 2023
Contingent Notes will mature on November 15, 2023. We may redeem some or all of
the notes at any time on or after November 22, 2009, at a redemption price,
payable in cash, of 100% of the principal amount of the notes, plus accrued and
unpaid interest and additional interest, if any, up to but not including the
date of redemption. Holders have the right to require us to repurchase all or a
portion of the 2023 Convertible Notes on November 22, 2009, 2013 and 2018, at
100% of their principal amount plus any accrued and unpaid interest. We have the
right to repurchase the 2023 Convertible Senior Notes with cash, shares of our
common stock, or a combination of cash and our common stock.
Item 6. Exhibits and Reports on Form 8-K.
(a)Exhibits
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
Exhibit
Number Description
- ------- ----------------------------------------------------------------------
*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation.(a)
*3.2 Certificate of Correction of Calpine Corporation.(b)
*3.3 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of Calpine Corporation.(c)
*3.4 Certificate of Designation of Series A Participating Preferred Stock
of Calpine Corporation.(b)
*3.5 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation.(b)
*3.6 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation.(c)
*3.7 Certificate of Designation of Special Voting Preferred Stock of
Calpine Corporation.(d)
*3.8 Certificate of Ownership and Merger Merging Calpine Natural Gas GP,
Inc. into Calpine Corporation.(e)
*3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas
Company into Calpine Corporation.(e)
*3.10 Amended and Restated By-laws of Calpine Corporation.(f)
*4.1.1 Indenture, dated as of May 16, 1996, between the Company and U.S. Bank
(as successor trustee to Fleet National Bank), as Trustee, including
form of Notes.(g)
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*4.1.2 First Supplemental Indenture, dated as of August 1, 2000, between the
Company and U.S. Bank National Association (as successor trustee to
Fleet National Bank), as Trustee.(b)
+4.1.3 Second Supplemental Indenture, dated as of April 26, 2004, between the
Company and U.S. Bank National Association (as successor trustee to
Fleet National Bank), as Trustee.
Exhibit
Number Description
- ------- ----------------------------------------------------------------------
*4.2.1 Indenture, dated as of July 8, 1997, between the Company and The Bank
of New York, as Trustee, including form of Notes.(h)
*4.2.2 Supplemental Indenture, dated as of September 10, 1997, between the
Company and The Bank of New York, as Trustee.(i)
*4.2.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.2.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.3.1 Indenture, dated as of March 31, 1998, between the Company and The
Bank of New York, as Trustee, including form of Notes.(j)
*4.3.2 Supplemental Indenture, dated as of July 24, 1998, between the Company
and The Bank of New York, as Trustee.(j)
*4.3.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.3.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.4.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(k)
*4.4.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.4.3 Second Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.5.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(k)
*4.5.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.5.3 Second Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.6.1 Indenture, dated as of August 14, 2003, among Calpine Construction
Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston,
LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as
Guarantors, and Wilmington Trust Company, as Trustee, including form
of Notes.(l)
*4.6.2 Supplemental Indenture, dated as of September 18, 2003, among Calpine
Construction Finance Company, L.P., CCFC Finance Corp., each of
Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust Company, as
Trustee.(l)
*4.6.3 Second Supplemental Indenture, dated as of January 14, 2004, among
Calpine Construction Finance Company, L.P., CCFC Finance Corp., each
of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust Company, as
Trustee.(m)
*4.6.4 Third Supplemental Indenture, dated as of March 5, 2004, among Calpine
Construction Finance Company, L.P., CCFC Finance Corp., each of
Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust Company, as
Trustee.(m)
*4.7 Amended and Restated Indenture, dated as of March 12, 2004, between
the Company and Wilmington Trust Company, including form of Notes.(m)
*4.8 First Priority Indenture, dated as of March 23, 2004, among Calpine
Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust
FSB, as Trustee, including form of Notes.(m)
*4.9 Second Priority Indenture, dated as of March 23, 2004, among Calpine
Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust
FSB, as Trustee, including form of Notes.(m)
*4.10 Third Priority Indenture, dated as of March 23, 2004, among Calpine
Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust
FSB, as Trustee, including form of Notes.(m)
*10.1.1 Amended and Restated Credit Agreement, dated as of March 23, 2004,
among Calpine Generating Company, LLC, the Guarantors named therein,
the Lenders named therein, The Bank of Nova Scotia, as Administrative
Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische
Landesbank Cayman Islands Branch, as Arranger and Co-Syndication
Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication
Agent, ING Capital LLC, as Arranger and Co-Syndication Agent,
Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent,
and Union Bank of California, N.A., as Arranger and Co-Syndication
Agent.(m)
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Exhibit
Number Description
- ------- ----------------------------------------------------------------------
*10.2.1 Amended and Restated Credit Agreement, dated as of July 16, 2003
("Amended and Restated Credit Agreement"), among the Company, the
Lenders named therein, The Bank of Nova Scotia, as Administrative
Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische
Landesbank, Cayman Islands Branch, as Lead Arranger, as Co-Bookrunner
and Documentation Agent, and ING Capital LLC and Toronto Dominion
(Texas) Inc., as Lead Arrangers, Co-Bookrunners and Syndication
Agents.(n)
*10.2.2 First Amendment to Amended and Restated Credit Agreement, dated as of
August 7, 2003, among the Company, the Lenders named therein, and The
Bank of Nova Scotia, as Administrative Agent and Funding Agent.(n)
*10.2.3 Amendment and Waiver to Amended and Restated Credit Agreement, dated
as of August 28, 2003, among the Company, the Lenders named therein,
and The Bank of Nova Scotia, as Administrative Agent and Funding
Agent.(l)
*10.2.4 Letter Agreement regarding Technical Correction to Amendment and
Waiver to Amended and Restated Credit Agreement, dated as of September
5, 2003, among the Company, the Lenders named therein, and The Bank of
Nova Scotia, as Administrative Agent and Funding Agent.(l)
*10.2.5 Third Amendment to Amended and Restated Credit Agreement, dated as of
November 6, 2003, among the Company, each of Quintana Minerals (USA)
Inc., JOQ Canada, Inc., and Quintana Canada Holdings, LLC, as a
Guarantor, the Lenders named therein, and The Bank of Nova Scotia, as
Administrative Agent and Funding Agent.(l)
*10.2.6 Fourth Amendment and Waiver to Amended and Restated Credit Agreement,
dated as of November 19, 2003, among the Company, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent.(m)
*10.2.7 Fifth Amendment and Waiver to Amended and Restated Credit Agreement,
dated as of December 30, 2003, among the Company, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent.(m)
*10.2.8 Technical Correction to Fifth Amendment and Waiver to Amended and
Restated Credit Agreement, dated as of December 31, 2003, among the
Company, the Lenders named therein, and The Bank of Nova Scotia, as
Administrative Agent and Funding Agent.(m)
*10.2.9 Waiver to Amended and Restated Credit Agreement, dated as of March 5,
2003, among the Company, the Lenders named therein, and The Bank of
Nova Scotia, as Administrative Agent and Funding Agent.(m)
*10.3.1 Credit and Guarantee Agreement, dated as of August 14, 2003, among
Calpine Construction Finance Company, L.P., each of Calpine Hermiston,
LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as
Guarantors, the Lenders named therein, and Goldman Sachs Credit
Partners L.P., as Administrative Agent and Sole Lead Arranger.(l)
*10.3.2 Amendment No. 1 to the Credit and Guarantee Agreement, dated as of
September 12, 2003, among Calpine Construction Finance Company, L.P.,
each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, the Lenders named therein, and Goldman
Sachs Credit Partners L.P., as Administrative Agent and Sole Lead
Arranger.(l)
*10.3.3 Amendment No. 2 to the Credit and Guarantee Agreement, dated as of
January 13, 2004, among Calpine Construction Finance Company, L.P.,
each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, the Lenders named therein, and Goldman
Sachs Credit Partners L.P., as Administrative Agent and Sole Lead
Arranger.(m)
*10.3.4 Amendment No. 3 to the Credit and Guarantee Agreement, dated as of
March 5, 2004, among Calpine Construction Finance Company, L.P., each
of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, the Lenders named therein, and Goldman
Sachs Credit Partners L.P., as Administrative Agent and Sole Lead
Arranger.(m)
*10.4 Credit and Guarantee Agreement, dated as of March 23, 2004, among
Calpine Generating Company, LLC, the Guarantors named therein, the
Lenders named therein, Morgan Stanley Senior Funding, Inc., as
Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole
Lead Arranger and Sole Bookrunner.(m)
*10.5 Credit and Guarantee Agreement, dated as of March 23, 2004, among
Calpine Generating Company, LLC, the Guarantors named therein, the
Lenders named therein, Morgan Stanley Senior Funding, Inc., as
Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole
Lead Arranger and Sole Bookrunner.(m)
*10.6 Consulting Contract, dated as of January 1, 2004, between Calpine
Corporation and Mr. George J. Stathakis. (m)(o)
+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.
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Exhibit
Number Description
- ------- ----------------------------------------------------------------------
+31.2 Certification of the Executive Vice President and Chief Financial
Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
+32.1 Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
- ----------
* Incorporated by reference.
+ Filed herewith.
(a) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30,
2000.
(b) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2000, filed with the SEC on March
15, 2001.
(c) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27,
2001.
(d) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.
(e) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.
(f) 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.
(g) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-06259) filed with the SEC on June 19,
1996.
(h) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
(i) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-41261) filed with the SEC on November
28, 1997.
(j) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-61047) filed with the SEC on August 10,
1998.
(k) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3/A (Registration No. 333-72583) filed with the SEC on March 8,
1999.
(l) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated September 30, 2003, filed with the SEC on November 13,
2003.
(m) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K dated December 31, 2003, filed with the SEC on March 25, 2004.
(n) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
(o) Management contract or compensatory plan or arrangement.
(b)Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the quarter
ended March 31, 2004:
Date of Report Date Filed Item Reported
----------------- ----------------- -------------
January 6, 2004 January 6, 2004 5
January 9, 2004 January 9, 2004 5
January 9, 2004 January 9, 2004 5
January 16, 2004 January 20, 2004 5
January 28, 2004 January 29, 2004 5
February 3, 2004 February 3, 2004 5
February 4, 2004 February 4, 2004 5
February 6, 2004 February 6, 2004 12
-68-
Date of Report Date Filed Item Reported
----------------- ----------------- -------------
February 9, 2004 February 9, 2004 5
February 20, 2004 February 24, 2004 5
February 24, 2004 February 24, 2004 5
February 26, 2004 March 1, 2004 12
March 10, 2004 March 10, 2004 5
March 11, 2004 March 12, 2004 5
March 12, 2004 March 16, 2004 5
March 23, 2004 March 23, 2004 5
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Calpine Corporation
By: /s/ ROBERT D. KELLY
-------------------------------------------
Robert D. Kelly
Executive Vice President and Chief Financial
Officer (Principal Financial Officer)
Date: May 10, 2004
By: /s/ CHARLES B. CLARK, JR.
-------------------------------------------
Charles B. Clark, Jr.
Senior Vice President and Corporate
Controller (Principal Accounting Officer)
Date: May 10, 2004
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The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
Exhibit
Number Description
- ------- ----------------------------------------------------------------------
*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation.(a)
*3.2 Certificate of Correction of Calpine Corporation.(b)
*3.3 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of Calpine Corporation.(c)
*3.4 Certificate of Designation of Series A Participating Preferred Stock
of Calpine Corporation.(b)
*3.5 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation.(b)
*3.6 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation.(c)
*3.7 Certificate of Designation of Special Voting Preferred Stock of
Calpine Corporation.(d)
*3.8 Certificate of Ownership and Merger Merging Calpine Natural Gas GP,
Inc. into Calpine Corporation.(e)
*3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas
Company into Calpine Corporation.(e)
*3.10 Amended and Restated By-laws of Calpine Corporation.(f)
*4.1.1 Indenture, dated as of May 16, 1996, between the Company and U.S. Bank
(as successor trustee to Fleet National Bank), as Trustee, including
form of Notes.(g)
*4.1.2 First Supplemental Indenture, dated as of August 1, 2000, between the
Company and U.S. Bank National Association (as successor trustee to
Fleet National Bank), as Trustee.(b)
+4.1.3 Second Supplemental Indenture, dated as of April 26, 2004, between the
Company and U.S. Bank National Association (as successor trustee to
Fleet National Bank), as Trustee.
*4.2.1 Indenture, dated as of July 8, 1997, between the Company and The Bank
of New York, as Trustee, including form of Notes.(h)
*4.2.2 Supplemental Indenture, dated as of September 10, 1997, between the
Company and The Bank of New York, as Trustee.(i)
*4.2.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.2.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.3.1 Indenture, dated as of March 31, 1998, between the Company and The
Bank of New York, as Trustee, including form of Notes.(j)
*4.3.2 Supplemental Indenture, dated as of July 24, 1998, between the Company
and The Bank of New York, as Trustee.(j)
*4.3.3 Second Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.3.4 Third Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.4.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(k)
*4.4.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.4.3 Second Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.5.1 Indenture, dated as of March 29, 1999, between the Company and The
Bank of New York, as Trustee, including form of Notes.(k)
*4.5.2 First Supplemental Indenture, dated as of July 31, 2000, between the
Company and The Bank of New York, as Trustee.(b)
+4.5.3 Second Supplemental Indenture, dated as of April 26, 2004, between the
Company and The Bank of New York, as Trustee.
*4.6.1 Indenture, dated as of August 14, 2003, among Calpine Construction
Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston,
LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as
Guarantors, and Wilmington Trust Company, as Trustee, including form
of Notes.(l)
*4.6.2 Supplemental Indenture, dated as of September 18, 2003, among Calpine
Construction Finance Company, L.P., CCFC Finance Corp., each of
Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust Company, as
Trustee.(l)
*4.6.3 Second Supplemental Indenture, dated as of January 14, 2004, among
Calpine Construction Finance Company, L.P., CCFC Finance Corp., each
of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust Company, as
Trustee.(m)
*4.6.4 Third Supplemental Indenture, dated as of March 5, 2004, among Calpine
Construction Finance Company, L.P., CCFC Finance Corp., each of
Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust Company, as
Trustee.(m)
*4.7 Amended and Restated Indenture, dated as of March 12, 2004, between
the Company and Wilmington Trust Company, including form of Notes.(m)
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Exhibit
Number Description
- ------- ----------------------------------------------------------------------
*4.8 First Priority Indenture, dated as of March 23, 2004, among Calpine
Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust
FSB, as Trustee, including form of Notes.(m)
*4.9 Second Priority Indenture, dated as of March 23, 2004, among Calpine
Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust
FSB, as Trustee, including form of Notes.(m)
*4.10 Third Priority Indenture, dated as of March 23, 2004, among Calpine
Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust
FSB, as Trustee, including form of Notes.(m)
*10.1.1 Amended and Restated Credit Agreement, dated as of March 23, 2004,
among Calpine Generating Company, LLC, the Guarantors named therein,
the Lenders named therein, The Bank of Nova Scotia, as Administrative
Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische
Landesbank Cayman Islands Branch, as Arranger and Co-Syndication
Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication
Agent, ING Capital LLC, as Arranger and Co-Syndication Agent,
Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent,
and Union Bank of California, N.A., as Arranger and Co-Syndication
Agent.(m)
*10.2.1 Amended and Restated Credit Agreement, dated as of July 16, 2003
("Amended and Restated Credit Agreement"), among the Company, the
Lenders named therein, The Bank of Nova Scotia, as Administrative
Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische
Landesbank, Cayman Islands Branch, as Lead Arranger, as Co-Bookrunner
and Documentation Agent, and ING Capital LLC and Toronto Dominion
(Texas) Inc., as Lead Arrangers, Co-Bookrunners and Syndication
Agents.(n)
*10.2.2 First Amendment to Amended and Restated Credit Agreement, dated as of
August 7, 2003, among the Company, the Lenders named therein, and The
Bank of Nova Scotia, as Administrative Agent and Funding Agent.(n)
*10.2.3 Amendment and Waiver to Amended and Restated Credit Agreement, dated
as of August 28, 2003, among the Company, the Lenders named therein,
and The Bank of Nova Scotia, as Administrative Agent and Funding
Agent.(l)
*10.2.4 Letter Agreement regarding Technical Correction to Amendment and
Waiver to Amended and Restated Credit Agreement, dated as of September
5, 2003, among the Company, the Lenders named therein, and The Bank of
Nova Scotia, as Administrative Agent and Funding Agent.(l)
*10.2.5 Third Amendment to Amended and Restated Credit Agreement, dated as of
November 6, 2003, among the Company, each of Quintana Minerals (USA)
Inc., JOQ Canada, Inc., and Quintana Canada Holdings, LLC, as a
Guarantor, the Lenders named therein, and The Bank of Nova Scotia, as
Administrative Agent and Funding Agent.(l)
*10.2.6 Fourth Amendment and Waiver to Amended and Restated Credit Agreement,
dated as of November 19, 2003, among the Company, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent.(m)
*10.2.7 Fifth Amendment and Waiver to Amended and Restated Credit Agreement,
dated as of December 30, 2003, among the Company, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent.(m)
*10.2.8 Technical Correction to Fifth Amendment and Waiver to Amended and
Restated Credit Agreement, dated as of December 31, 2003, among the
Company, the Lenders named therein, and The Bank of Nova Scotia, as
Administrative Agent and Funding Agent.(m)
*10.2.9 Waiver to Amended and Restated Credit Agreement, dated as of March 5,
2003, among the Company, the Lenders named therein, and The Bank of
Nova Scotia, as Administrative Agent and Funding Agent.(m)
*10.3.1 Credit and Guarantee Agreement, dated as of August 14, 2003, among
Calpine Construction Finance Company, L.P., each of Calpine Hermiston,
LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as
Guarantors, the Lenders named therein, and Goldman Sachs Credit
Partners L.P., as Administrative Agent and Sole Lead Arranger.(l)
*10.3.2 Amendment No. 1 to the Credit and Guarantee Agreement, dated as of
September 12, 2003, among Calpine Construction Finance Company, L.P.,
each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, the Lenders named therein, and Goldman
Sachs Credit Partners L.P., as Administrative Agent and Sole Lead
Arranger.(l)
*10.3.3 Amendment No. 2 to the Credit and Guarantee Agreement, dated as of
January 13, 2004, among Calpine Construction Finance Company, L.P.,
each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, the Lenders named therein, and Goldman
Sachs Credit Partners L.P., as Administrative Agent and Sole Lead
Arranger.(m)
*10.3.4 Amendment No. 3 to the Credit and Guarantee Agreement, dated as of
March 5, 2004, among Calpine Construction Finance Company, L.P., each
of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, the Lenders named therein, and Goldman
Sachs Credit Partners L.P., as Administrative Agent and Sole Lead
Arranger.(m)
-72-
Exhibit
Number Description
- ------- ----------------------------------------------------------------------
*10.4 Credit and Guarantee Agreement, dated as of March 23, 2004, among
Calpine Generating Company, LLC, the Guarantors named therein, the
Lenders named therein, Morgan Stanley Senior Funding, Inc., as
Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole
Lead Arranger and Sole Bookrunner.(m)
*10.5 Credit and Guarantee Agreement, dated as of March 23, 2004, among
Calpine Generating Company, LLC, the Guarantors named therein, the
Lenders named therein, Morgan Stanley Senior Funding, Inc., as
Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole
Lead Arranger and Sole Bookrunner.(m)
*10.6 Consulting Contract, dated as of January 1, 2004, between Calpine
Corporation and Mr. George J. Stathakis. (m)(o)
+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.
- ----------
* Incorporated by reference.
+ Filed herewith.
(a) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30,
2000.
(b) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2000, filed with the SEC on March
15, 2001.
(c) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27,
2001.
(d) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.
(e) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.
(f) 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.
(g) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-06259) filed with the SEC on June 19,
1996.
(h) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.
(i) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-41261) filed with the SEC on November
28, 1997.
(j) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-4 (Registration No. 333-61047) filed with the SEC on August 10,
1998.
(k) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3/A (Registration No. 333-72583) filed with the SEC on March 8,
1999.
(l) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated September 30, 2003, filed with the SEC on November 13,
2003.
(m) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K dated December 31, 2003, filed with the SEC on March 25, 2004.
(n) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
(o) Management contract or compensatory plan or arrangement.
-73-