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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 2002
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 the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
376,699,769 shares of Common Stock, par value $.001 per share, outstanding on
August 8, 2002
In the Company's 2001 Report on Form 10-K the Company disclosed that it
dismissed Arthur Andersen LLP effective March 29, 2002, as its independent
public accountants and appointed Deloitte and Touche LLP as its new independent
public accountants. Pursuant to Temporary Note 2T to Article 3 of Regulation
S-X, the quarterly report on Form 10-Q for the three months ended March 31,
2002, has subsequently been reviewed by Deloitte and Touche LLP in accordance
with Statement on Auditing Standards No. 71, "Interim Financial Information."
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CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Quarter Ended June 30, 2002
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Condensed Balance Sheets June 30, 2002 and December 31, 2001........................... 3
Consolidated Condensed Statements of Operations For the Three and Six Months
Ended June 30, 2002 and 2001...................................................................... 4
Consolidated Condensed Statements of Cash Flows For the Six Months
Ended June 30, 2002 and 2001...................................................................... 6
Notes to Consolidated Condensed Financial Statements June 30, 2002.................................. 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 25
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................. 45
PART II - OTHER INFORMATION
Item 1. Legal Proceedings...................................................................................... 46
Item 4. Submission of Matters to a Vote of Security Holders.................................................... 47
Item 6. Exhibits and Reports on Form 8-K....................................................................... 48
Signatures........................................................................................................ 51
-2-
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Balance Sheets
June 30, 2002 and December 31, 2001
(In thousands, except share and per share amounts)
June 30, December 31,
2002 2001
------------ -------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents.................................................................... $ 528,767 $ 1,525,417
Accounts receivable, net..................................................................... 1,009,552 966,080
Margin deposits and other prepaid expense.................................................... 244,454 480,656
Inventories.................................................................................. 96,662 78,862
Current derivative assets.................................................................... 583,943 763,162
Other current assets......................................................................... 227,948 193,525
------------ ------------
Total current assets...................................................................... 2,691,326 4,007,702
------------ ------------
Restricted cash................................................................................. 107,298 95,833
Notes receivable, net of current portion........................................................ 173,155 158,124
Project development costs....................................................................... 187,372 179,783
Investments in power projects................................................................... 431,046 378,614
Deferred financing costs........................................................................ 229,739 210,811
Property, plant and equipment, net.............................................................. 17,118,306 15,276,056
Goodwill and other intangible assets, net....................................................... 140,984 153,115
Long-term derivative assets..................................................................... 665,787 564,952
Other assets.................................................................................... 484,723 304,562
------------ ------------
Total assets............................................................................ $ 22,229,736 $ 21,329,552
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................................................................. $ 1,250,424 $ 1,283,843
Accrued payroll and related expense.......................................................... 49,899 57,285
Accrued interest payable..................................................................... 186,302 160,115
Notes payable and borrowings under lines of credit, current portion.......................... 10,523 23,238
Capital lease obligation, current portion.................................................... 2,277 2,206
Construction/project financing, current portion.............................................. 147,363 --
Zero-Coupon Convertible Debentures Due 2021.................................................. -- 878,000
Current derivative liabilities............................................................... 473,140 625,339
Other current liabilities.................................................................... 202,377 198,812
------------ ------------
Total current liabilities................................................................. 2,322,305 3,228,838
------------ ------------
Term loan....................................................................................... 1,000,000 --
Notes payable and borrowings under lines of credit, net of current portion...................... 77,453 74,750
Capital lease obligation, net of current portion................................................ 206,700 207,219
Construction/project financing, net of current portion.......................................... 3,434,097 3,393,410
Convertible Senior Notes Due 2006............................................................... 1,200,000 1,100,000
Senior notes.................................................................................... 7,085,886 7,049,038
Deferred income taxes, net...................................................................... 938,566 964,346
Deferred lease incentive........................................................................ 55,484 57,236
Deferred revenue................................................................................ 201,766 154,381
Long-term derivative liabilities................................................................ 580,919 822,848
Other liabilities............................................................................... 95,163 96,504
------------ ------------
Total liabilities....................................................................... 17,198,339 17,148,570
------------ ------------
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts.. 1,123,537 1,123,024
Minority interests.............................................................................. 40,000 47,389
------------ ------------
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and
outstanding one share in 2002 and 2001...................................................... -- --
Common stock, $.001 par value per share; authorized 1,000,000,000 shares in 2002 and 2001;
issued and outstanding 375,602,307 shares in 2002 and 307,058,751 shares in 2001............ 376 307
Additional paid-in capital...................................................................... 2,791,942 2,040,836
Retained earnings............................................................................... 1,194,249 1,196,000
Accumulated other comprehensive loss............................................................ (118,707) (226,574)
------------ ------------
Total stockholders' equity................................................................... 3,867,860 3,010,569
------------ ------------
Total liabilities and stockholders' equity................................................ $ 22,229,736 $ 21,329,552
============ ============
The accompanying notes are an integral part of these
consolidated condensed financial statements.
-3-
CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Operations
For the Three and Six Months Ended June 30, 2002 and 2001
(In thousands, except per share amounts)
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- ------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue.......................... $ 708,752 $ 505,711 $ 1,328,931 $ 1,100,870
Sales of purchased power............................... 868,606 683,196 1,776,907 1,136,798
Electric power derivative mark-to-market gain.......... 6,104 68,433 10,270 69,739
------------ ------------ ------------ ------------
Total electric generation and marketing revenue...... 1,583,462 1,257,340 3,116,108 2,307,407
Oil and gas production and marketing revenue
Oil and gas sales...................................... 52,163 116,319 119,651 273,006
Sales of purchased gas................................. 302,044 226,693 434,202 355,865
------------ ------------ ------------ ------------
Total oil and gas production and marketing revenue... 354,207 343,012 553,853 628,871
Income (loss) from unconsolidated investments in
power projects........................................... (1,121) 1,600 323 2,163
Other revenue............................................. 5,258 10,921 9,869 14,183
------------ ------------ ------------ ------------
Total revenue..................................... 1,941,806 1,612,873 3,680,153 2,952,624
------------ ------------ ------------ ------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense................................ 118,930 69,259 234,087 153,719
Royalty expense........................................ 4,194 6,916 8,349 17,925
Purchased power expense................................ 698,176 655,322 1,513,181 1,111,588
------------ ------------ ------------ ------------
Total electric generation and marketing expense...... 821,300 731,497 1,755,617 1,283,232
Oil and gas production and marketing expense
Oil and gas production expense......................... 27,836 27,308 54,776 61,591
Purchased gas expense.................................. 333,724 218,330 457,418 336,958
------------ ------------ ------------ ------------
Total oil and gas production and marketing expense... 361,560 245,638 512,194 398,549
Fuel expense
Cost of oil and natural gas burned by power plants..... 350,848 251,876 677,291 516,439
Natural gas derivative mark-to-market loss (gain)...... 3,203 (23,446) 9,595 (30,995)
------------ ------------ ------------ ------------
Total fuel expense................................... 354,051 228,430 686,886 485,444
Depreciation, depletion and amortization expense.......... 110,122 72,144 213,995 144,157
Operating lease expense................................... 36,263 27,449 72,397 55,460
Other expense............................................. 2,204 3,490 4,794 5,989
------------ ------------ ------------ ------------
Total cost of revenue............................. 1,685,500 1,308,648 3,245,883 2,372,831
------------ ------------ ------------ ------------
Gross profit................................... 256,306 304,225 434,270 579,793
Project development expense.................................. 24,713 4,372 36,051 20,211
Equipment cancellation cost.................................. -- -- 168,471 --
General and administrative expense........................... 53,601 50,537 113,862 86,622
Merger expense............................................... -- 35,606 -- 41,627
------------ ------------ ------------ ------------
Income from operations.................................... 177,992 213,710 115,886 431,333
Interest expense............................................. 67,058 43,331 128,369 63,256
Distributions on trust preferred securities.................. 15,387 15,387 30,773 30,562
Interest income.............................................. (9,762) (20,531) (21,938) (39,889)
Other income, net............................................ (2,766) (3,291) (11,859) (9,018)
------------ ------------ ------------ ------------
Income (loss) before provision (benefit) for income taxes. 108,075 178,814 (9,459) 386,422
Provision (benefit) for income taxes......................... 35,559 69,849 (5,578) 158,830
------------ ------------ ------------ ------------
Income (loss) before extraordinary gain (loss) and
cumulative effect of a change in accounting principle.... 72,516 108,965 (3,881) 227,592
Extraordinary gain (loss), net of tax provision of $--, $834,
$1,362 and $834............................................. -- (1,300) 2,130 (1,300)
Cumulative effect of a change in accounting principle,
net of tax provision of $--, $--, $--and $669............... -- -- -- 1,036
------------ ------------ ------------ ------------
Net income (loss).............................. $ 72,516 $ 107,665 $ (1,751) $ 227,328
============ ============ ============ ============
-4-
CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Operations
For the Three and Six Months Ended June 30, 2002 and 2001
(In thousands, except per share amounts)
(unaudited)
(continued)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- ------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding....... 356,158 302,729 331,745 301,641
Income (loss) before extraordinary gain (loss) and
cumulative effect of a change in accounting principle.... $ 0.20 $ 0.36 $ (0.01) $ 0.75
Extraordinary gain (loss)................................. $ -- $ -- $ -- $ --
Cumulative effect of a change in accounting principle..... $ -- $ -- $ -- $ --
------------ ------------ ------------ ------------
Net income (loss).............................. $ 0.20 $ 0.36 $ (0.01) $ 0.75
============ ============ ============ ============
Diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding before
dilutive effect of certain convertible securities........ 365,606 318,255 331,745 317,544
Income (loss) before dilutive effect of certain
convertible securities, extraordinary gain (loss) and
cumulative effect of a change in accounting principle.... $ 0.20 $ 0.34 $ (0.01) $ 0.72
Dilutive effect of certain convertible securities (1)..... $ (0.01) $ (0.02) $ -- $ (0.04)
------------ ------------ ------------ ------------
Income (loss) before extraordinary gain (loss) and
cumulative effect of a change in accounting principle.... $ 0.19 $ 0.32 $ (0.01) $ 0.68
Extraordinary gain (loss)................................. $ -- $ -- $ -- $ --
Cumulative effect of a change in accounting principle..... $ -- $ -- $ -- $ --
------------ ------------ ------------ ------------
Net income (loss).............................. $ 0.19 $ 0.32 $ (0.01) $ 0.68
============ ============ ============ ============
- ----------
(1) Includes the effect of the assumed conversion of certain dilutive
convertible securities. No convertible securities were included in the six
months ended 2002 amounts as the securities were antidilutive. For the
three months ended June 30, 2002, and for the three and six months ended
June 30, 2001, the assumed conversion calculation added 85,320, 41,964 and
49,379 shares of common stock and $11,306, $7,507 and $20,838 to the net
income results, respectively.
The accompanying notes are an integral part of these
consolidated condensed financial statements.
-5-
CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Cash Flows
For the Six Months Ended June 30, 2002 and 2001
(In thousands)
(unaudited)
Six Months Ended
June 30,
-------------------------------
2002 2001
------------- -------------
Cash flows from operating activities:
Net income (loss)............................................................................ $ (1,751) $ 227,328
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization.................................................. 244,540 148,552
Equipment cancellation cost............................................................... 168,471 --
Development cost write-off................................................................ 22,300 --
Deferred income taxes, net................................................................ 115,953 123,937
Gain on sale of assets.................................................................... (11,513) (10,750)
Minority interests........................................................................ (948) 3,157
Income from unconsolidated investments in power projects.................................. (323) (2,163)
Distributions from unconsolidated investments in power projects........................... 18 2,459
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable..................................................................... (43,472) (315,344)
Notes receivable........................................................................ (10,404) (43,624)
Current derivative assets............................................................... 179,219 (1,048,198)
Other current assets.................................................................... 197,001 (36,253)
Long-term derivative assets............................................................. (100,835) (874,306)
Other assets............................................................................ 6,025 (9,918)
Accounts payable and accrued expense.................................................... (17,000) 131,502
Current derivative liabilities.......................................................... (152,199) 689,931
Long-term derivative liabilities........................................................ (241,903) 957,448
Other liabilities....................................................................... 56,006 42,471
Other comprehensive income relating to derivatives...................................... 54,260 103,744
------------ ------------
Net cash provided by operating activities............................................ 463,445 89,973
------------ ------------
Cash flows from investing activities:
Purchases of property, plant and equipment................................................... (2,479,037) (2,557,041)
Disposals of property, plant and equipment and investments in power projects................. 49,822 19,134
Advances to joint ventures................................................................... (43,823) (63,871)
Decrease (increase) in notes receivable...................................................... 2,859 (93,723)
Maturities of collateral securities.......................................................... 3,325 2,885
Project development costs.................................................................... (63,654) (55,314)
Increase in restricted cash.................................................................. (27,814) (24,705)
------------ ------------
Net cash used in investing activities................................................ (2,558,322) (2,772,635)
------------ ------------
Cash flows from financing activities:
Proceeds from issuance of Zero-Coupon Convertible Debentures Due 2021........................ -- 1,000,000
Repurchase of Zero-Coupon Convertible Debentures Due 2021.................................... (873,227) --
Borrowings from term loan notes payable and lines of credit.................................. 1,077,453 258
Repayments of notes payable and repayments under lines of credit............................. (87,465) (444,568)
Borrowings from project financing............................................................ 280,248 1,479,673
Repayments of project financing.............................................................. (92,198) (1,234,433)
Proceeds from issuance of Convertible Senior Notes Due 2006.................................. 100,000 --
Proceeds from issuance of senior notes....................................................... -- 2,650,000
Repayments of senior notes................................................................... -- (105,000)
Proceeds from issuance of common stock....................................................... 751,172 49,369
Financing costs.............................................................................. (59,925) (64,534)
Other........................................................................................ (1,789) (2,660)
------------ ------------
Net cash provided by financing activities............................................ 1,094,269 3,328,105
------------ ------------
Effect of exchange rate changes on cash and cash equivalents.................................... 3,958 --
Net increase (decrease) in cash and cash equivalents............................................ (996,650) 645,443
Cash and cash equivalents, beginning of period.................................................. 1,525,417 596,077
------------ ------------
Cash and cash equivalents, end of period........................................................ $ 528,767 $ 1,241,520
============ ============
Cash paid during the period for:
Interest, net of amounts capitalized......................................................... $ 59,809 $ (7,351)
Income taxes................................................................................. $ 13,043 $ 114,083
The accompanying notes are an integral part of these
consolidated condensed financial statements.
-6-
CALPINE CORPORATION AND SUBSIDIARIES
Notes to Consolidated Condensed Financial Statements
June 30, 2002
(unaudited)
1. Organization and Operation of the Company
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, "the Company") is engaged in the generation of electricity in the
United States, Canada and the United Kingdom. The Company is involved in the
development, acquisition, 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. In Canada, the Company owns power facilities
and oil and gas operations. In the United Kingdom, the Company owns 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, 2001, 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. The Company's historical amounts have been restated
to reflect the pooling-of-interests transaction completed during the second
quarter of 2001 for the acquisition of Encal Energy Ltd. ("Encal").
Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expense during the reporting
period. Actual results could differ from those estimates. The most significant
estimates with regard to these financial statements relate to useful lives and
carrying values of assets (including the carrying value of projects in
development, construction and operation), provision for income taxes, fair value
calculations of derivative instruments and depletion, depreciation and
impairment of natural gas and petroleum property and equipment. See the
"Critical Accounting Policies" subsection in the Management's Discussion and
Analysis of Financial Condition and Results of Operations in the Company's
Annual Report on Form 10-K for the year ended December 31, 2001, for a further
discussion of the Company's significant estimates.
Revenue Recognition -- The Company is primarily an electric generation
company, operating a portfolio of mostly wholly owned plants but also some
plants in which its ownership interest is 50% or less and which are accounted
for under the equity method. In conjunction with its electric generation
business, the Company also produces, as a by-product, thermal energy for sale to
customers, principally steam hosts at the Company's cogeneration sites. In
addition, the Company acquires and produces natural gas for its own consumption
and sells the balance and oil produced to third parties. To protect and enhance
the profit potential of its electric generation plants, the Company, through its
subsidiary, Calpine Energy Services, L.P. ("CES"), enters into electric and gas
hedging, balancing, and optimization transactions, subject to market conditions,
and CES has also, from time to time, entered into contracts considered energy
trading contracts under Emerging Issues Task Force ("EITF") Issue No. 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." CES executes these transactions primarily through the use of
physical forward commodity purchases and sales and financial commodity swaps and
options. With respect to its physical forward contracts, CES generally acts as a
principal, takes title to the commodities, and assumes the risks and rewards of
ownership. Therefore, in accordance with Staff Accounting Bulletin No. 101,
"Revenue Recognition in Financial Statements" and EITF Issue No. 99-19,
"Reporting Revenue Gross as a Principal Versus Net as an Agent," CES recognizes
revenue from settlement of its physical forward contracts on a gross basis. CES
settles its financial swap and option transactions net and does not take title
to the underlying commodity. Accordingly, CES records gains and losses from
settlement of financial swaps and options net in income. Managed risks typically
include commodity price risk associated with fuel purchases and power sales.
-7-
It is our policy not to engage in "roundtrip" trades. We have conducted a
detailed analysis of our records looking for instances of transactions that may
have the characteristics of "roundtrip" trades (i.e., trades with the same
counterparty at the same time, price and location) for the period from January
1, 2000 through June 30, 2002, and have determined that while there were a very
small number of transactions with such characteristics, there was no material
impact on our financial statements from any such trades and none were conducted
for the purpose of increasing trading volume, revenue, or market prices or for
any other improper purpose.
The Company, through its wholly owned subsidiary, Power Systems Mfg., LLC
("PSM"), designs and manufactures certain spare parts for gas turbines. The
Company also generates small amounts of revenue by occasionally loaning funds to
power projects, by providing operation and maintenance ("O&M") services to
unconsolidated power projects, and by performing engineering services for data
centers and other facilities requiring highly reliable power. Further details of
the Company's revenue recognition policy for each type of revenue transaction
are provided below:
Electric Generation and Marketing Revenue -- This includes electricity and
steam sales, mark-to-market gains and losses from electric power derivatives and
sales of purchased power. Subject to market and other conditions, the Company
manages the revenue stream for its portfolio of electric generating facilities.
The Company markets on a system basis both power generated by its plants in
excess of amounts under direct contract between the plant and a third party, and
power purchased from third parties, through hedging, balancing, optimization and
trading transactions. CES performs a market-based allocation of total electric
generation and marketing revenue, exclusive of mark-to-market activity, to
electricity and steam sales (based on electricity delivered by the Company's
electric generating facilities to serve CES contracts) and the balance is
allocated to sales of purchased power. Sales of purchased power also include
revenue from the settlement of contracts that had been previously recorded in
results of operations as electric power derivative mark-to-market gains or
losses prior to realization.
Oil and Gas Production and Marketing Revenue -- This includes sales to
third parties of oil, gas and related products that are produced by the
Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and,
subject to market and other conditions, sales of purchased gas arising from
hedging, balancing, optimization and trading transactions. Sales of purchased
gas also include revenue from the settlement of contracts that had been
previously recorded in results of operations as natural gas derivative
mark-to-market gains or losses, prior to realization. Oil and gas sales for
produced products are recognized pursuant to the sales method.
Income from Unconsolidated Investments in Power Projects -- The Company
uses the equity method to recognize as revenue its pro rata share of the net
income or loss of the unconsolidated investment until such time, if applicable,
that the Company's investment is reduced to zero, at which time equity income is
generally recognized only upon receipt of cash distributions from the investee.
Other Revenue -- This includes O&M contract revenue, interest income on
loans to power projects, PSM revenue from sales to third parties, engineering
revenue and miscellaneous revenue.
Purchased Power and Purchased Gas Expense -- The cost of power purchased
from third parties for hedging, balancing, optimization and trading activities,
along with costs from the subsequent settlement of contracts that had been
previously recorded in results of operations as electric power derivative
mark-to-market gains or losses, prior to realization, are recorded as purchased
power expense, a component of electric generation and marketing expense.
The Company records the cost of gas consumed in its power plants as cost of
oil and natural gas burned by power plants, while gas purchased from third
parties for hedging, balancing, optimization and trading activities, along with
costs from the subsequent settlement of contracts that had been previously
recorded in results of operations as natural gas derivative mark-to-market gains
or losses, prior to realization, are recorded as purchased gas expense, a
component of oil and gas production and marketing expense.
Derivative Instruments -- Financial Accounting Standards Board ("FASB")
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" as amended by SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133 -- an Amendment of FASB Statement No.
133," and as further amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities -- an Amendment of FASB Statement No.
133," together with related guidance from the Derivatives Implementation Group,
established accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value unless exempted from derivative treatment as a normal
purchase and sale. The statement requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge criteria are
met, and requires that a company must formally document, designate, and assess
the effectiveness of transactions that receive hedge accounting.
-8-
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 ("OCI") 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 perfectly
effective, such amounts recorded in earnings will be equal and offsetting.
SFAS No. 133 requires that as of the date of initial adoption, the
difference between the fair value of derivative instruments and the previous
carrying amount of these derivatives be recorded in net income or OCI, as
appropriate, as the cumulative effect of a change in accounting principle. Upon
adoption of SFAS No. 133 effective January 1, 2001, the Company recorded the
cumulative effect of a change in accounting principle of $1.0 million (net of a
$0.7 million tax provision) to net income and $39.8 million (net of a $25.7
million tax provision) to OCI.
New Accounting Pronouncements -- In June 2001 the Company adopted SFAS No.
141, "Business Combinations," which supersedes Accounting Principles Board
("APB") Opinion No. 16, "Business Combinations" and SFAS No. 38, "Accounting for
Preacquisition Contingencies of Purchased Enterprises." SFAS No. 141 eliminated
the pooling-of-interests method of accounting for business combinations and
modified the recognition of intangible assets and disclosure requirements. The
adoption of SFAS No. 141 did not have a material effect on the Company's
consolidated financial statements.
On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which supersedes APB Opinion No. 17, "Intangible Assets."
See Note 4 for more information.
In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which amends SFAS No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies." SFAS No. 143 addresses financial accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. SFAS No. 143
requires that the fair value of a liability for an asset retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of
fair value can be made. SFAS No. 143 is effective for financial statements
issued for fiscal years beginning after June 15, 2002. The Company does not
believe that SFAS No. 143 will have a material impact on its consolidated
financial statements.
On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions of APB Opinion No.
30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," for the disposal of a segment of a business (as
previously defined in that APB Opinion). SFAS No. 144 establishes a single
accounting model, based on the framework established in SFAS No. 121, for
long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several
significant implementation issues related to SFAS No. 121, such as eliminating
the requirement to allocate goodwill to long-lived assets to be tested for
impairment and establishing criteria to define whether a long-lived asset is
held for sale. Adoption of SFAS No. 144 has not had a material effect on the
Company's consolidated financial statements.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" stating that
gains or losses from extinguishment of debt that fall outside of the scope of
APB Opinion No. 30 should not be classified as extraordinary. SFAS No. 145 also
amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency
between the required accounting for sale-leaseback transactions and the required
accounting for certain lease modifications that have economic effects that are
similar to sale-leaseback transactions. SFAS No. 145 also amends other existing
authoritative pronouncements to make various technical corrections, clarify
meanings, or describe their applicability under changed conditions. The
provisions related to the rescission of SFAS No. 4 shall be applied in fiscal
years beginning after May 15, 2002. The provisions related to SFAS No. 13 shall
be effective for transactions occurring after May 15, 2002. All other provisions
shall be effective for financial statements issued on or after May 15, 2002,
with early adoption encouraged. The Company has not completed its analysis but
believes that SFAS No. 145 may have a material effect on the presentation of its
financial statements but no impact on net income.
-9-
In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (Including Certain
Costs Incurred in a Restructuring)." The Company will adopt the provisions of
SFAS No. 146 for restructuring activities initiated after December 31, 2002.
SFAS No. 146 requires that the liability for costs associated with an exit or
disposal activity be recognized when the liability is incurred. Under Issue No.
94-3, a liability for an exit cost was recognized at the date of commitment to
an exit plan. SFAS No. 146 also establishes that the liability should initially
be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the
timing of recognizing future restructuring costs as well as the amounts
recognized. The Company does not believe that SFAS No. 146 will have a material
effect on its consolidated financial statements.
In June 2002 the EITF reached a consensus on two of the three issues
considered in EITF 02-03, "Recognition and Reporting of Gains and Losses on
Energy Trading Contracts under EITF Issues No. 98-10, `Accounting for Contracts
Involved in Energy Trading and Risk Management Activities' and No. 00-17,
`Measuring the Fair Value of Energy-Related Contracts in applying Issue No.
98-10.'" The issues upon which the EITF reached a consensus required net
presentation of energy trading contracts in a company's financial statements and
required that companies make certain disclosures regarding their energy trading
contracts. The net presentation requirement is effective for financial
statements issued for periods ending after July 15, 2002, and the disclosure
requirements are effective for financial statements issued for fiscal years
ending after July 15, 2002. The Company is still assessing the impacts of
adopting this standard on its financial statements, but believes that, at a
minimum, all energy trading contracts will be reported net, rather than gross,
upon adoption of this standard. The standard is expected to have a material
impact on total revenues and expenses, but no impact on net income.
Reclassifications -- Prior period amounts in the consolidated condensed
financial statements have been reclassified where necessary to conform to the
2002 presentation.
3. Property, Plant and Equipment, and Capitalized Interest
Property, plant and equipment, net, consisted of the following (in
thousands):
June 30, December 31,
2002 2001
------------- -------------
Buildings, machinery and equipment......................................... $ 7,382,378 $ 4,690,484
Oil and gas properties, including pipelines................................ 2,420,500 2,283,344
Geothermal properties...................................................... 393,472 371,156
Other...................................................................... 326,404 223,675
------------ ------------
10,522,754 7,568,659
Less: Accumulated depreciation, depletion and amortization............. (1,088,505) (855,065)
------------ ------------
9,434,249 6,713,594
Land....................................................................... 90,794 80,506
Construction in progress................................................... 7,593,263 8,481,956
------------ ------------
Property, plant and equipment, net......................................... $ 17,118,306 $ 15,276,056
============ ============
Construction in progress is primarily attributable to gas-fired power
projects under construction including prepayments on gas 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. In March 2002 the Company announced a change in its turbine and
construction program that will slow the growth in the Company's construction in
progress. See Note 13 for a discussion of the turbine order cancellations during
the first quarter.
During the second quarter of 2002, the Company reclassified $203.7 million
of turbine costs from construction in progress to other assets, as the turbines
will not be used for the Company's current power plant development program. The
Company recorded a $14.2 million charge to project development expense to effect
a reduction in the carrying value of such turbines. The Company currently
anticipates that some of the turbines will be used for future power plants and
others may be sold to third parties. The Company is now in negotiations to
cancel or restructure the contracts for up to 89 units. The Company expects to
complete these negotiations in the fourth quarter of 2002. The Company may also,
subject to market conditions, take steps to further adjust or restructure
turbine orders, including canceling additional turbine orders, consistent with
the Company's power plant construction and development programs.
-10-
Capitalized Interest -- The Company capitalizes interest on capital
invested in projects during the advanced stages of development and the
construction period in accordance with SFAS No. 34, "Capitalization of Interest
Cost," as amended by SFAS No. 58, "Capitalization of Interest Cost in Financial
Statements That Include Investments Accounted for by the Equity Method (an
Amendment of FASB Statement No. 34)." The Company's qualifying assets include
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. During the three months
ended June 30, 2002 and 2001, the total amount of interest capitalized was
$171.0 million and $115.6 million, including $37.0 million and $31.2 million,
respectively, of interest incurred on funds borrowed for specific construction
projects and $134.0 million and $84.4 million, respectively, of interest
incurred on general corporate funds used for construction. During the six months
ended June 30, 2002 and 2001, the total amount of interest capitalized was
$334.1 million and $219.6 million, including $72.1 million and $65.9 million,
respectively, of interest incurred on funds borrowed for specific construction
projects and $262.0 million and $153.7 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 increase in
the amount of interest capitalized during 2002, compared to 2001, reflects the
significant increase in the Company's power plant construction program. However,
the Company expects that the amount of interest capitalized will decrease in
future periods as the power plants in construction are completed and as a 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 are the Company's senior notes, the Company's term loan facility and
the Company's revolving credit facilities.
4. Goodwill and Other Intangible Assets
On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which requires that all intangible assets with finite useful
lives be amortized and that goodwill and intangible assets with indefinite lives
not be amortized, but rather tested upon adoption and at least annually for
impairment. The Company was required to complete the initial step of a
transitional impairment test within six months of adoption of SFAS No. 142 and
to complete the final step of the transitional impairment test by the end of the
fiscal year. Any future impairment losses will be reflected in operating income
or loss in the consolidated statements of operations. The Company completed the
transitional goodwill impairment test as required and determined that the fair
value of the reporting units holding goodwill exceeded their net carrying
values. Therefore, the Company did not record any impairment expense.
In accordance with the standard, the Company discontinued the amortization
of its recorded goodwill as of January 1, 2002, and identified reporting units
based on its current segment reporting structure and allocated all recorded
goodwill, as well as other assets and liabilities, to the reporting units. A
reconciliation of previously reported net income and earnings per share to the
amounts adjusted for the exclusion of goodwill amortization is provided below
(in thousands, except per share amounts):
Three Months Ended June 30,
--------------------------------------------------------------------
2002 2001
-------------------------------- --------------------------------
Per Share Per Share
------------------ ------------------
Amount Diluted Basic Amount Diluted Basic
---------- ------- ------ ---------- ------- ------
Reported income before extraordinary
items and cumulative effect of accounting changes.... $ 72,516 $ 0.19 $ 0.20 $ 108,965 $ 0.32 $ 0.36
Add: Goodwill amortization...................... -- -- -- 205 -- --
Pro forma income before extraordinary items and
cumulative effect of accounting changes.............. 72,516 0.19 0.20 109,170 0.32 0.36
Extraordinary items and cumulative effect of
accounting changes, net of tax....................... -- -- -- (1,300) -- --
---------- ------ ------ ---------- ------ ------
Pro forma net income............................ $ 72,516 $ 0.19 $ 0.20 $ 107,870 $ 0.32 $ 0.36
========== ====== ====== ========== ====== ======
-11-
Six Months Ended June 30,
--------------------------------------------------------------------
2002 2001
-------------------------------- --------------------------------
Per Share Per Share
------------------ ------------------
Amount Diluted Basic Amount Diluted Basic
---------- ------- ------ ---------- ------- ------
Reported income (loss) before extraordinary
items and cumulative effect of accounting changes. $ (3,881) $(0.01) $(0.01) $ 227,592 $ 0.68 $ 0.75
Add: Goodwill amortization...................... -- -- -- 341 -- 0.01
Pro forma income (loss) before extraordinary items
and cumulative effect of accounting changes.......... (3,881) (0.01) (0.01) 227,933 0.68 0.76
Extraordinary items and cumulative effect of
accounting changes, net of tax....................... 2,130 -- -- (264) -- --
---------- ------ ------ ---------- ------ ------
Pro forma net income (loss)..................... $ (1,751) $(0.01) $(0.01) $ 227,669 $ 0.68 $ 0.76
========== ====== ====== ========== ====== ======
Recorded goodwill, by segment, as of June 30, 2002, was (in thousands):
Electric Generation and Marketing........................ $ 29,348
Oil and Gas Production and Marketing..................... --
Corporate, Other and Eliminations........................ --
---------
Total................................................. $ 29,348
=========
Subsequent goodwill impairment tests will be performed, at a minimum, in
the fourth quarter of each year, in conjunction with the Company's annual
reporting process.
The Company also reassessed the useful lives and the classification of its
identifiable intangible assets and determined that they continue to be
appropriate. The components of the amortizable intangible assets consist of the
following (in thousands):
As of June 30, 2002 As of December 31, 2001
-------------------------- --------------------------
Weighted
Average
Useful
Life/Contract Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------- ---------- ------------ ---------- ------------
Patents...................................... 5 $ 485 $ (182) $ 485 $ (134)
Power sales agreements....................... 14 173,090 (100,103) 173,090 (88,178)
Fuel supply and fuel management contracts.... 26 22,198 (3,660) 22,198 (3,216)
Geothermal lease rights...................... 20 19,493 (300) 19,493 (250)
Other........................................ 5 662 (47) 277 (25)
---------- ---------- ---------- ----------
Total..................................... $ 215,928 $ (104,292) $ 215,543 $ (91,803)
========== ========== ========== ==========
Amortization expense of other intangible assets was $6.2 million and $1.0
million in the three months ended June 30, 2002 and 2001, respectively, and
$12.4 million and $2.0 million in the six months ended June 30, 2002 and 2001,
respectively. Assuming no future impairments of these assets or additions as the
result of acquisitions, annual amortization expense will be $22.0 million for
the twelve months ended December 31, 2002, $5.9 million in 2003, $5.4 million in
2004, $5.3 million in 2005 and $5.2 million in 2006.
5. Investments in Power Projects
On March 29, 2002, the Company sold its 11.4% interest in the Lockport
Power Plant in exchange for a $27.3 million note receivable from Fortistar
Tuscarora LLC, a wholly owned subsidiary of Fortistar LLC, the project's
managing general partner. This transaction resulted in a pre-tax other income
gain of $9.7 million. The note was repaid in the second quarter of 2002.
6. Financing
On January 31, 2002, the Company's subsidiary, Calpine Construction
Management Company, Inc., entered into an agreement with Siemens Westinghouse
Power Corporation to reschedule the production and delivery of gas and steam
turbine generators and related equipment. Under the agreement, the Company
obtained vendor financing of up to $232.0 million bearing variable interest for
other gas and steam turbine generators and related equipment. The financing is
-12-
due prior to the earliest of the equipment site delivery date specified in the
agreement, the Company's requested date of turbine site delivery or June 25,
2003. At March 31, 2002 and June 30, 2002, there were $0 and $47.4 million,
respectively, in borrowings outstanding under this agreement.
On April 30, 2002, the Company completed a registered offering of 66
million shares of its common stock at $11.50 per share. The proceeds from this
offering, after underwriting fees, were $734.3 million.
On April 30, 2002, the Company repurchased the remaining $685.5 million in
aggregate principal amount of its Zero Coupon Convertible Debentures due 2021
("Zero Coupons") at par pursuant to a scheduled put provided for by the terms of
the Zero Coupons.
On May 14, 2002, the Company's subsidiary, Calpine California Energy
Finance, LLC, entered into an amended and restated credit agreement with ING
Capital LLC for the funding of 9 California peaker facilities, of which $100.0
million was drawn on May 24, 2002. The total $100.0 million funding is
classified as current project financing, of which $50.0 million was repaid on
August 7, 2002, and $50.0 million will be payable on September 30, 2002. This
peaker funding is part of the Company's expected long-term financing of its
California peaker facilities which is anticipated to be $500.0 million.
On May 31, 2002, the Company increased its two-year secured bank term loan
to $1.0 billion from $600.0 million, and reduced the size of its secured
corporate revolving credit facilities to $1.0 billion from $1.4 billion. At June
30, 2002, the Company has $1.0 billion in funded borrowings outstanding under
the term loan facility, and $75.0 million in funded borrowings and $723.2
million outstanding in letters of credit under the revolving credit facility.
In 2003 and 2004, $981.4 million and $2,452.7 million, respectively, under
the Company's secured revolving construction financing facilities will mature,
requiring the Company to refinance this indebtedness.
7. DePere Transaction
On June 28, 2002, the Company executed a definitive agreement with
Wisconsin Public Service for the sale of its 180-megawatt DePere Energy Center.
This agreement is subject to certain conditions, including the receipt of
regulatory approval by the State of Wisconsin, which is expected to be decided
in September 2002. If the agreement is approved by regulatory authorities,
Wisconsin Public Service would pay the Company $120.4 million for the DePere
facility and the existing power purchase agreement would be terminated.
8. 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
and (to a lesser extent) other commodities, the Company enters into derivative
commodity instruments. The Company enters into commodity financial instruments
to convert floating or indexed electricity and gas (and to a lesser extent oil
and refined product) 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. Any
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. 98-10. 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
and EITF Issue No. 98-10.
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 that are
not deemed normal purchases and sales can be designated as hedges of the
underlying consumption of gas or production of electricity.
-13-
In 2001 the FASB cleared SFAS No. 133 Implementation Issue No. C16
"Applying the Normal Purchases and Normal Sales Exception to Contracts That
Combine a Forward Contract and a Purchased Option Contract" ("C16"). The
guidance in C16 applies to fuel supply contracts that require delivery of a
contractual minimum quantity of fuel at a fixed price and have an option that
permits the holder to take specified additional amounts of fuel at the same
fixed price at various times. Under C16, the volumetric optionality provided by
such contracts is considered a purchased option that disqualifies the entire
derivative fuel supply contract from being eligible to qualify for the normal
purchases and normal sales exception in SFAS No. 133. On April 1, 2002, the
Company adopted C16. At June 30, 2002, the Company had no fuel supply contracts
to which C16 applies. However, one of the Company's equity method investees has
fuel supply contracts subject to C16. The equity investee also adopted C16 on
April 1, 2002. The contracts qualified as highly effective hedges of the equity
method investee's forecasted purchase of gas. Accordingly, the Company has
recorded $7.8 million net of tax as a cumulative effect of change in accounting
principle to other comprehensive income for its share of the equity method
investee's other comprehensive income from accounting change.
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 June 30, 2002, for the Company's derivative
instruments:
Commodity
Interest Rate Currency Derivative Total
Derivative Derivative Instruments Derivative
Instruments Instruments Net Instruments
------------- ----------- ----------- -----------
Current derivative assets............................... $ -- $ 199 $ 583,744 $ 583,943
Long-term derivative assets............................. -- 4,167 661,620 665,787
----------- ----------- ----------- -----------
Total assets......................................... $ -- $ 4,366 $ 1,245,364 $ 1,249,730
=========== =========== =========== ===========
Current derivative liabilities.......................... $ 10,178 $ 609 $ 462,353 $ 473,140
Long-term derivative liabilities........................ 12,483 -- 568,436 580,919
----------- ----------- ----------- -----------
Total liabilities.................................... $ 22,661 $ 609 $ 1,030,789 $ 1,054,059
=========== =========== =========== ===========
Net derivative assets (liabilities)............... $ (22,661) $ 3,757 $ 214,575 $ 195,671
=========== =========== =========== ===========
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, thereby creating an imbalance between net OCI and net
derivative assets and liabilities.
-14-
o Derivatives not designated as cash flow hedges and hedge
ineffectiveness -- Only derivatives that qualify as effective cash
flow hedges will have an offsetting amount recorded in OCI.
Derivatives not designated as cash flow hedges and the ineffective
portion of derivatives designated as cash flow hedges will be recorded
into earnings instead of OCI, creating a difference between net
derivative assets and liabilities and pre-tax OCI from derivatives.
o Termination of effective cash flow hedges prior to maturity --
Following the termination of a cash flow hedge and subsequent
settlement with a counterparty, the derivative asset or liability is
liquidated and removed from the books. At this point, no asset or
liability exists on the books for the hedge instrument but a balance
remains in OCI, which is not recognized in earnings until the
forecasted 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
June 30, 2002 (in thousands):
Net derivative assets......................................................................... $ 195,671
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness........... (165,955)
Cash flow hedges terminated prior to maturity................................................. (277,804)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges... 81,474
Accumulated OCI from unconsolidated investees (1)............................................. 31,743
Other reconciling items....................................................................... 5,754
----------
Accumulated other comprehensive loss from derivative instruments, net of tax.................. $ (129,117)
==========
(1) Includes $12.8 million (pre-tax) relating to the cumulative effect of
accounting change from unconsolidated investee. See discussion of New
Accounting Pronouncements in Note 2 of the financial statements.
The asset and liability balances for the Company's commodity derivative
instruments represent the net totals after offsetting certain assets against
certain liabilities under the criteria of FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB
Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract,
FIN 39 will allow the offsetting of assets against liabilities so long as four
criteria are met: (1) each of the two parties under contract owes the other
determinable amounts; (2) the party reporting under the offset method has the
right to set off the amount it owes against the amount owed to it by the other
party; (3) the party reporting under the offset method intends to exercise its
right to set off; and; (4) the right of set-off is enforceable by law. The table
below reflects both the amounts (in thousands) recorded as assets and
liabilities by the Company and the amounts that would have been recorded had the
Company's commodity derivative instrument contracts not qualified for offsetting
as of June 30, 2002.
June 30, 2002
------------------------------
Gross Net
------------ ------------
Current derivative assets..................... $ 1,733,012 $ 583,744
Long-term derivative assets................... 835,937 661,620
------------ ------------
Total derivative assets.................... $ 2,568,949 $ 1,245,364
============ ============
Current derivative liabilities................ $ 1,611,620 $ 462,353
Long-term derivative liabilities 742,754 568,436
------------ ------------
Total derivative liabilities............... $ 2,354,374 $ 1,030,789
============ ============
Net commodity derivative assets......... $ 214,575 $ 214,575
============ ============
The table above excludes the value of interest rate and currency derivative
instruments.
The tables below reflect the impact of the Company's derivative instruments
on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the
changes in market value of derivatives not designated as hedges of cash flows,
for the three and six months ended June 30, 2002 and 2001, respectively (in
thousands):
-15-
Three Months Ended June 30,
-------------------------------------------------------------------------------------------
2002 2001
------------------------------------------ --------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ ------- --------------- ----------- ---------
Natural gas and crude oil
derivatives....................... $ 990 $(4,193) $(3,203) $(3,998) $ 27,444 $ 23,446
Power derivatives.................. (1,002) 7,106 6,104 1,217 67,216 68,433
Interest rate derivatives (1)...... (188) -- (188) (17) -- (17)
Foreign currency derivatives....... -- -- -- -- -- --
------- ------- ------- ------- -------- ---------
Total........................... $ (200) $ 2,913 $ 2,713 $(2,798) $ 94,660 $ 91,862
======= ======= ======= ======== ======== =========
Six Months Ended June 30,
-------------------------------------------------------------------------------------------
2002 2001
------------------------------------------ --------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ ------- --------------- ----------- ---------
Natural gas and crude oil
derivatives....................... $(1,605) $(7,990) $(9,595) $(3,472) $ 34,467 $ 30,995
Power derivatives.................. (1,224) 11,494 10,270 -- 69,739 69,739
Interest rate derivatives (1)...... (340) -- (340) (17) -- (17)
Foreign currency derivatives....... -- -- -- -- -- --
------- ------- ------- ------- -------- ---------
Total........................... $(3,169) $ 3,504 $ 335 $(3,489) $104,206 $ 100,717
======= ======= ======= ======= ======== =========
(1) Recorded within Other Income
For the three and six months ended June 30, 2002 and 2001, the Company's
realized commodity cash flow hedge activity contributed $36.0 million and $86.8
million, respectively, and $4.8 million and $21.8 million, respectively, to
pre-tax earnings based on the reclassification adjustment from OCI to earnings.
For the three and six months ended June 30, 2002 and 2001, power hedges
contributed $75.3 million and $161.8 million, respectively, and $3.1 million and
$(6.2) million, respectively, to pre-tax earnings. For the three and six months
ended June 30, 2002 and 2001, gas and crude oil hedges contributed $(39.3)
million and $(75.0) million, respectively, and $1.7 million and $28.0 million,
respectively, to pre-tax earnings. For the three and six months ended June 30,
2002, interest rate hedges contributed $(2.6) million and $(4.6) million,
respectively, to pre-tax earnings. For the three and six months ended June 30,
2002, currency hedges contributed $(2.8) million and $(2.8) million,
respectively, to pre-tax earnings. For the three and six months ended June 30,
2001, interest rate hedges and currency hedges did not impact the Company's
pre-tax earnings.
As of June 30, 2002, the maximum length of time over which the Company was
hedging its exposure to the variability in future cash flows for forecasted
transactions was 6, 6 1/2, and 12 years, for commodity, foreign currency and
interest rate derivative instruments, respectively. The Company estimates that
pre-tax gains of $13.8 million would be reclassified from accumulated OCI into
earnings during the twelve months ended June 30, 2003, 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.
-16-
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.
2007
2002 2003 2004 2005 2006 & After Total
--------- --------- --------- --------- --------- --------- ----------
Crude oil OCI................. $ (1,024) $ -- $ -- $ -- $ -- $ -- $ (1,024)
Gas OCI....................... (48,633) (188,244) (56,318) (56,760) (11,607) 13,092 (348,470)
Power OCI..................... 141,834 67,361 6,318 1,908 6,586 (818) 223,189
Interest rate OCI............. (9,273) (14,763) (11,112) (9,435) (8,607) (25,698) (78,888)
Foreign currency OCI.......... (238) (781) (554) (589) (553) (2,683) (5,398)
--------- --------- --------- -------- -------- -------- ---------
Total OCI.................. $ 82,666 $(136,427) $(61,666) $(64,876) $(14,181) $(16,107) $(210,591)
========= ========= ======== ======== ======== ======== =========
9. Comprehensive Income (Loss)
Comprehensive income (loss) is the total of net income (loss) and all other
non-owner changes in equity. Comprehensive income (loss) includes net income
(loss) and unrealized gains and losses from derivative instruments that qualify
as cash flow hedges. The Company reports accumulated other comprehensive loss in
its consolidated balance sheet. The tables below detail the changes in the
Company's accumulated OCI balance and the components of the Company's
comprehensive income (loss) (in thousands):
Accumulated Other Comprehensive Income (Loss)
At June 30, 2002
-------------------------------------------------------------------
Foreign
Cash Flow Currency Comprehensive
Hedges Translation Total Income / (Loss)
----------- ----------- ----------- ---------------
Net loss for the three months ended March 31, 2002............ $ (74,267)
Accumulated other comprehensive loss at
December 31, 2001............................................ $ (183,377) $ (43,197) $ (226,574)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the three
months ended March 31, 2002............................ 120,610
Reclassification adjustment for gain included in net
loss for the three months ended March 31, 2002......... (48,699)
Income tax provision for the three months ended
March 31, 2002......................................... (28,153)
----------
43,758 43,758 43,758
Foreign currency translation loss for the three months
ended March 31, 2002...................................... (25,170) (25,170) (25,170)
---------- ---------- ----------
Total comprehensive loss for the three months ended
March 31, 2002............................................... $ (55,679)
==========
Accumulated other comprehensive loss at March 31, 2002........ $ (139,619) $ (68,367) $ (207,986)
========== ========== ==========
Net income for the three months ended June 30, 2002........... $ 72,516
Accumulated other comprehensive loss at March 31, 2002........ $ (139,619) $ (68,367) $ (207,986)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the three
months ended June 30, 2002............................. 47,855
Reclassification adjustment for gain included in net
income for the three months ended June 30, 2002....... (30,617)
Income tax provision for the three months ended
June 30, 2002.......................................... (6,736)
----------
10,502 10,502 10,502
Foreign currency translation gain for the three months
ended June 30, 2002....................................... 78,777 78,777 78,777
---------- ---------- ---------- ----------
Total comprehensive income for the three months ended
June 30, 2002................................................ 161,795
----------
Total comprehensive income for the six months ended
June 30, 2002................................................ $ 106,116
==========
Accumulated other comprehensive income/(loss) at
June 30, 2002................................................ $ (129,117) $ 10,410 $ (118,707)
========== ========== ==========
-17-
Accumulated Other Comprehensive Income (Loss)
At June 30, 2001
-------------------------------------------------------------------
Foreign
Cash Flow Currency Comprehensive
Hedges Translation Total Income / (Loss)
----------- ----------- ----------- ---------------
Net income for the three months ended March 31, 2001 $ 119,663
Accumulated other comprehensive loss at
December 31, 2000............................................ $ -- $ (23,085) $ (23,085)
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the three
months ended March 31, 2001............................ (69,134)
Reclassification adjustment for gain included in net
loss for the three months ended March 31, 2001......... (17,047)
Income tax provision for the three months ended
March 31, 2001......................................... 32,611
----------
(53,570) (53,570) (53,570)
Foreign currency translation gain for the three months
ended March 31, 2001...................................... 14,694 14,694 14,694
---------- ---------- ---------- ----------
Total comprehensive income for the three months ended
March 31, 2001............................................... $ 80,787
==========
Accumulated other comprehensive loss at March 31, 2001........ $ (53,570) $ (8,391) $ (61,961)
========== ========== ==========
Net income for the three months ended June 30, 2001........... $ 107,665
Accumulated other comprehensive loss at March 31, 2001........ $ (53,570) $ (8,391) $ (61,961)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the three
months ended June 30, 2001............................. 263,714
Reclassification adjustment for gain included in net
income for the three months ended June 30, 2001........ (4,745)
Income tax provision for the three months ended
June 30, 2001.......................................... (102,047)
----------
156,922 156,922 156,922
Foreign currency translation loss for the three months
ended June 30, 2001....................................... (16,550) (16,550) (16,550)
---------- ---------- ---------- ----------
Total comprehensive income for the three months ended
June 30, 2001................................................ 248,037
----------
Total comprehensive income for the six months ended
June 30, 2001................................................ $ 328,824
==========
Accumulated other comprehensive income (loss) at
June 30, 2001................................................ $ 103,352 $ (24,941) $ 78,411
========== ========== ==========
10. Customers
Enron
During 2001 the Company, primarily through its CES subsidiary, transacted a
significant volume of business with units of Enron Corp. ("Enron"), mainly Enron
Power Marketing, Inc. ("EPMI") and Enron North America Corp. ("ENA"). ENA is the
parent corporation of EPMI. Enron is the direct parent corporation of ENA. Most
of these transactions were contracts for sales and purchases of power and gas
for hedging purposes, the terms of which extended out as far as 2009. On
December 2, 2001, Enron Corp. and certain of its subsidiaries, including EPMI
and ENA, filed voluntary petitions for Chapter 11 reorganization with the U.S.
Bankruptcy Court for the Southern District of New York.
The Company has conducted no business with EPMI or ENA since December 31,
2001. The following table sets forth information regarding the Company's settled
physical transactions and non-hedging mark-to-market gains with Enron for the
three and six months ended June 30, 2001, (in thousands of dollars and thousands
of MWh's, in the case of electricity transactions, and thousands of MMBtu's, in
the case of oil and gas transactions):
-18-
For the Three Months Ended For the Six Months Ended
June 30, 2001 June 30, 2001
-------------------------- --------------------------
Dollar Volume Dollar Volume
--------- ---------- --------- ----------
Electric generation and marketing revenue (electricity and
steam revenue and sales of purchased power)................. $ 264,716 2,869 $ 348,891 4,162
Oil and gas production and marketing revenue (sales of
purchased gas).............................................. 92,969 9,315 146,259 11,369
Other revenue................................................ 676 -- 2,050 --
--------- ---------
Total power and fuel and other revenue from Enron......... $ 358,361 $ 497,200
--------- ---------
Electric generation and marketing expense (purchased
power expense).............................................. $ 254,340 2,119 $ 365,226 3,401
Fuel expense (cost of oil and natural gas burned by power
plants and natural gas derivative mark-to-market gain)...... 70,475 10,626 87,405 13,043
--------- ---------
Total CES power and fuel expenses related to Enron (1)..... $ 324,815 $ 452,631
========= =========
- ----------
(1) Expenses of CES only, as other Enron expenses incurred are not material.
The Company has terminated all of its open forward positions with ENA and
EPMI, and will settle with ENA and EPMI based on the value of the terminated
contracts at the termination or replacement date, as applicable. Accordingly,
all net amounts associated with terminated ENA and EPMI forward contracts have
been included within the Company's accounts payable. During 2001 and prior to
the termination of its forward contracts with ENA and EPMI, certain of the
Company's ENA and EPMI contracts had been designated as cash flow hedges.
Accordingly, prior to termination of these positions, balances had accumulated
in OCI. As of June 30, 2002, the Company had remaining unrealized pre-tax losses
of $183.4 million on derivatives previously designated as effective cash flow
hedges. These amounts will be recognized in future earnings as the original
hedged forecasted transactions occur.
The sales to and purchases from various Enron subsidiaries were mostly for
hedging, balancing, optimization and trading transactions, and in most cases the
purchases and sales are not related and should not be netted to try to gauge the
profitability of transactions with Enron subsidiaries.
On November 14, 2001, CES, ENA and EPMI entered into a Master Netting,
Setoff and Security Agreement (the "Netting Agreement"). The Netting Agreement
permits CES, on the one hand, and ENA and EPMI, on the other hand, to set off
amounts owed to each other under an ISDA Master Agreement between CES and ENA,
an Enfolio Master Firm Purchase/Sale Agreement between CES and ENA and a Master
Energy Purchase/Sale Agreement between CES and EPMI (in each case, after giving
effect to the netting provisions contained in each of these agreements). Based
on legal analysis of the Netting Agreement, the Company believes it has no net
collection exposure to Enron.
After netting the receivables from and payables to ENA and EPMI, based on
certain assumptions, the Company has calculated an existing or future obligation
to Enron of approximately $143.5 million as of June 30, 2002, which obligation
the Company expects will be offset by CES' losses, damages, attorneys' fees and
other expenses arising from the default by Enron, and which amount is included
in the Company's accounts payable balance at June 30, 2002.
Nevada Power and Sierra Pacific Power Company
During the first quarter of 2002, two subsidiaries of Sierra Pacific
Resources Company, Nevada Power Company ("NPC") and Sierra Pacific Power Company
("SPPC"), received credit downgrades to sub-investment grades from the major
credit rating agencies. Additionally, NPC acknowledged liquidity problems
created when the Public Utilities Commission of Nevada disallowed a rate
adjustment requested by NPC to cover the increased cost of buying power during
the 2001 energy crisis. NPC has requested that its power suppliers extend
payment terms to help it overcome its short-term liquidity problems. During the
second quarter of 2002, NPC indicated to its power suppliers that it was
experiencing cash flow difficulties. In June and July 2002 NPC underpaid the
Company by approximately $4.2 million, and the Company expects that NPC will
underpay the Company by approximately an additional $18.4 million this summer
and early fall, with repayments of deferred amounts beginning at some point
thereafter once NPC's cash flow stabilizes. In consideration of the uncertainty
surrounding NPC's ability to make timely payments, the Company is maintaining a
bad debt reserve of approximately $2.7 million against NPC receivables, which
will be closely monitored. In addition, NPC and SPPC filed with the Federal
Energy Regulatory Commission ("FERC") under Section 206 of the Federal Power Act
- - see Note 13 for further discussion.
-19-
As of June 30, 2002, the Company had net collection exposures of
approximately $34.8 million and $20.2 million with NPC and SPPC, respectively.
However, SPPC is paying the Company currently. The Company's exposures include
open forward power contracts that are reported at fair value on the Company's
balance sheet as well as receivable and payable balances relating to prior power
deliveries. Management is continuing to monitor the exposure and its effect on
the Company's financial condition. The table below details the components of the
Company's exposure position at June 30, 2002 (in millions of dollars). The
positive net positions represent realization exposure while the negative net
positions represent the Company's existing or potential obligations.
Receivables/Payables Fair Values
-------------------------------------- -----------------------------------------------------
Net Gross Gross Net Open
Gross Gross Receivable Fair Value Fair Value Positions
Receivable Payable (Payable) (+) (-) Value Total
---------- --------- ---------- ---------- ----------- --------- -------
NPC........................... $ 23.6 $ (18.7) $ 4.9 $ 74.6 $ (44.7) $ 29.9 $ 34.8
SPPC.......................... 1.4 -- 1.4 18.8 -- 18.8 20.2
------- ------- ------- ------- ------- ------- -------
Total...................... $ 25.0 $ (18.7) $ 6.3 $ 93.4 $ (44.7) $ 48.7 $ 55.0
======= ======= ======= ======= ======= ======= =======
Under the terms of its contracts with NPC and SPPC, the Company believes
that it has the right to offset asset and liability positions.
PSM License Receivable
In December 2001 PSM and a Dutch power services company entered into a
perpetual world-wide license agreement for certain PSM proprietary reverse-flow
venturi technology. The license fee, while earned upfront, is payable over the
period from January 2002 through March 2004. The Company recognized the license
fee of $11 million (less imputed interest on the receivable) as income in
December 2001. As of the date of this filing, the Company has a receivable of $7
million, with no payments currently past due. The indirect parent of the Dutch
company, a German holding company, filed for insolvency in Germany in July 2002
and the direct parent of the Dutch company is expected to also file for
insolvency. However, the Dutch company has assured the Company that it has not
and currently does not expect to file for insolvency in the near term. The
Company has been further assured in a letter from the German holding company
dated July 11, 2002, that the Dutch company expects to continue the license
arrangement and to meet its obligations thereunder. Based on the Company's
evaluation of these and other factors, a loss does not seem probable at this
time. Accordingly, the Company has not established a reserve against the related
receivable but will continue to closely monitor the situation.
Credit Evaluations
The Company's treasury department includes a credit group focused on
monitoring and managing counterparty risk. The credit group monitors the net
exposure with each counterparty on a daily basis. The analysis is performed on a
mark-to-market basis using the forward curves analyzed by the Company's Risk
Controls group. The net exposure is compared against a counterparty credit risk
threshold which is determined based on the counterparty's credit ratings,
evaluation of the financial statements and bond values. The credit department
monitors these thresholds to determine the need for additional collateral or an
adjustment to activity with the counterparty.
11. Earnings (Loss) Per Share
Basic earnings (loss) per common share were computed by dividing net income
(loss) by the weighted average number of common shares outstanding for the
period. 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 interest expense and distribution expense avoided
upon conversion. The reconciliation of basic earnings (loss) per common share to
diluted earnings (loss) per share is shown in the following table (in thousands,
except per share data).
-20-
Periods Ended June 30,
---------------------------------------------------------------------------
2002 2001
---------------------------------- ------------------------------------
Net Net
Income Shares EPS Income Shares EPS
--------- -------- ------ --------- -------- -------
THREE MONTHS:
Basic earnings per common share:
Income before extraordinary loss and
cumulative effect of a change in accounting
principle......................................... $ 72,516 356,158 $ 0.20 $ 108,965 302,729 $ 0.36
Extraordinary loss, net of tax..................... -- -- -- (1,300) -- --
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- -- -- --
--------- ------- ------ --------- ------- ------
Net income ................................... $ 72,516 356,158 $ 0.20 $ 107,665 302,729 $ 0.36
========= ------- ====== ========= ------- ======
Diluted earnings per common share:
Common shares issuable upon exercise of stock
options using treasury stock method............... 9,448 15,526
------- -------
Income before dilutive effect of certain
convertible securities, extraordinary loss and
cumulative effect of a change in accounting
principle......................................... $ 72,516 365,606 0.20 $ 108,965 318,255 $ 0.34
Dilutive effect of certain convertible securities.. 11,306 85,320 (0.01) 7,507 41,964 (0.02)
--------- ------- ------ --------- ------- ------
Income before extraordinary loss and
cumulative effect of a change in accounting
principle......................................... 83,822 450,926 0.19 116,472 360,219 0.32
Extraordinary loss, net of tax..................... -- -- -- (1,300) -- --
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- -- -- --
--------- ------- ------ --------- ------- ------
Net income ................................... $ 83,822 450,926 $ 0.19 $ 115,172 360,219 $ 0.32
========= ======= ====== ========= ======= ======
Periods Ended June 30,
---------------------------------------------------------------------------
2002 2001
---------------------------------- ------------------------------------
Net Net
Income Income
(Loss) Shares EPS (Loss) Shares EPS
--------- -------- ------ --------- -------- -------
SIX MONTHS:
Basic earnings (loss) per common share:
Income (loss) before extraordinary gain (loss)
and cumulative effect of a change in accounting
principle......................................... $ (3,881) 331,745 $(0.01) $ 227,592 301,641 $ 0.75
Extraordinary gain (loss), net of tax.............. 2,130 -- -- (1,300) -- --
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- 1,036 -- --
--------- ------- ------ --------- ------- ------
Net income (loss)............................. $ (1,751) 331,745 $(0.01) $ 227,328 301,641 $ 0.75
========= ------- ====== ========= ------- ======
Diluted earnings (loss) per common share:
Common shares issuable upon exercise of stock
options using treasury stock method............... -- 15,903
------- -------
Income (loss) before dilutive effect of certain
convertible securities, extraordinary gain (loss)
and cumulative effect of a change in accounting
principle......................................... $ (3,881) 331,745 $(0.01) $ 227,592 317,544 $ 0.72
Dilutive effect of certain convertible securities.. -- -- -- 20,838 49,379 (0.04)
--------- ------- ------ --------- ------- ------
Income (loss) before extraordinary gain (loss)
and cumulative effect of a change in accounting
principle......................................... (3,881) 331,745 (0.01) 248,430 366,923 0.68
Extraordinary gain (loss), net of tax.............. 2,130 -- -- (1,300) -- --
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- 1,036 -- --
--------- ------- ------ --------- ------- ------
Net income (loss)............................. $ (1,751) 331,745 $(0.01) $ 248,166 366,923 $ 0.68
========= ======= ====== ========= ======= ======
-21-
For the three and six months ended June 30, 2002 and for the three and six
months ended June 30, 2001, respectively, the effect of 38,237, 145,819, 25,886
and 13,597 thousand unexercised employee stock options, Company-obligated
mandatorily redeemable convertible preferred securities of subsidiary trusts,
Zero Coupons and Convertible Senior Notes Due 2006, were not included in the
computation of diluted shares outstanding because such inclusion would have been
antidilutive.
12. Stock Compensation
The Company accounts for qualified stock compensation under APB Opinion No.
25, "Accounting for Stock Issued to Employees." Had compensation cost been
determined consistent with the methodology of SFAS No. 123, "Accounting for
Stock-Based Compensation," which provides for the accounting of options as
compensation expense, the Company's net income (loss) and earnings (loss) per
share would have been changed to the following pro forma amounts (in thousands,
except per share amounts):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- ---------------------------
2002 2001 2002 2001
-------- --------- --------- ---------
Net income (loss)
As reported............................................ $ 72,516 $ 107,665 $ (1,751) $ 227,328
Pro Forma.............................................. 67,543 99,650 (15,585) 212,020
Earnings (loss) per share data:
Basic earnings (loss) per share
As reported............................................ $ 0.20 $ 0.36 $ (0.01) $ 0.75
Pro Forma.............................................. 0.19 0.33 (0.05) 0.70
Diluted earnings (loss) per share
As reported............................................ $ 0.19 $ 0.32 $ (0.01) $ 0.68
Pro Forma.............................................. 0.17 0.30 (0.05) 0.64
For the three and six months ended June 30, 2002 and 2001, respectively,
the fair value of options granted was $9.76 and $7.74, and $39.01 and $35.36 on
the dates of grant using the Black-Scholes option pricing model with the
following weighted-average assumptions: expected dividend yields of 0%, expected
volatility of 97% for the three and six months ended June 30, 2002, and 64% for
the three and six months ended June 30, 2001, risk-free interest rates of 4.86%
for the three and six months ended June 30, 2002, and 5.42% for the three and
six months ended June 30, 2001, and expected lives of 10 years for the three and
six months ended June 30, 2002 and 2001, respectively.
13. Commitments and Contingencies
Capital Expenditures -- On March 12, 2002, the Company announced a new
turbine program that reduces previously forecasted capital spending by
approximately $1.2 billion in 2002 and $1.8 billion in 2003. The revision
includes adjusted timing of turbine delivery and related payment schedules and
also turbine order cancellations. As a result of the turbine order cancellations
and the cancellation of certain other equipment, the Company recorded a pre-tax
charge of $168.5 million in the first quarter of 2002, based primarily on
forfeited prepayments to date and an immaterial cash payment pursuant to
contract terms.
Litigation--
Securities Derivative Lawsuit. On December 17, 2001, a shareholder filed a
derivative lawsuit on behalf of the Company against its directors and one of its
senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. (No.
CV803872), and is pending in the California Superior Court, Santa Clara County.
The Company is a nominal defendant in this lawsuit, which alleges claims
relating to purportedly misleading statements about the Company and stock sales
by certain of the director defendants and the officer defendant. The Company has
filed a demurrer asking the court to dismiss the complaint on the ground that
the shareholder plaintiff lacks standing to pursue claims on behalf of the
Company. The individual defendants have filed a demurrer asking the court to
dismiss the complaint on the ground that it fails to state any claims against
them. The Company considers this lawsuit to be without merit and intends to
vigorously defend against it.
Securities Class Action Lawsuits. Fourteen shareholder lawsuits have been
filed against the Company and certain of its officers in the United States
District Court, 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
-22-
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 were 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 the Company's securities between January 5, 2001, and
December 13, 2001.
The complaints in these fourteen actions allege that, during the purported
class periods, certain senior Calpine executives issued false and misleading
statements about the Company'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. The Company expects that these actions, as well as any related
actions that may be filed in the future, will be consolidated by the court into
a single securities class action.
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 to those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of the
Company'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 Prospectus Supplement dated October 11, 2001, for the 2011 Notes
contained false and misleading statements regarding the Company's financial
condition. This action names the Company, 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. The Company
expects that this action will either be consolidated with the above-referenced
actions or will proceed as a parallel related action before the same judge
presiding over the other actions.
The Company considers the allegations against Calpine in each of these
lawsuits to be without merit, and intends to defend vigorously against them.
California Business & Professions Code Section 17200 Cases. The lead case,
T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al., was
served on May 2, 2002, by T&E Pastorino Nursery, on behalf of itself and all
others similarly situated. This purported class action complaint against twenty
energy traders and energy companies including CES, alleges that defendants
exercised market power and manipulated prices in violation of California
Business & Professions Code Section 17200 et seq., and seeks injunctive relief,
restitution and attorneys' fees.
The Company also has been named in five other similar complaints for
violations of Section 17200 captioned Bronco Don Holdings, LLP. v. Duke Energy
Marketing and Trading, et al.; Century Theatres, Inc. v. Allegheny Energy Supply
Company, LLC; RDJ Farms, Inc. v. Allegheny Energy Supply Company, LLC; J&M
Karsant Family Limited Partnership v. Duke Energy Trading and Marketing, LLC;
and Leo's Day and Night Pharmacy v. Duke Energy Trading and Marketing, LLC. All
six of these cases have been removed in a multidistrict litigation proceeding
from the various state courts in which they were originally filed to federal
court, where a motion is now pending to transfer and consolidate these cases for
pretrial proceedings with other cases in which the Company is not named as a
defendant. In addition, plaintiffs in the T&E Pastorino Nursery case have filed
a motion to remand that matter to California state court.
The Company considers the allegations against Calpine in each of these
lawsuits to be without merit, and intends to vigorously defend against them.
California Department of Water Resources Case. On May 1, 2002, California
State Senator Tom McClintock and others filed a complaint against Vikram
Budhraja, a consultant to the California Department of Water Resources ("DWR"),
DWR itself, and more than twenty-nine energy providers and other interested
parties, including the Company. The complaint alleges that the long-term power
contracts that DWR entered into with these energy providers, including the
Company, are rendered void because Budhraja, who negotiated the contracts on
behalf of DWR, allegedly had an undisclosed financial interest in the contracts
due to his connection to one of the energy providers, Edison International.
Among other things, the complaint seeks an injunction prohibiting further
performance of the long-term contracts and restitution of any funds paid to
energy providers by the State of California under the contracts. The Company
considers the allegations against Calpine in this lawsuit to be without merit,
and intends to vigorously defend against them.
Nevada Section 206 Complaint. On December 4, 2001, NPC and SPPC filed a
complaint with the FERC under Section 206 of the Federal Power Act against a
number of parties to their power sales agreements, including the Company. NPC
and SPPC allege in their complaint, which seeks a refund, that the prices they
-23-
agreed to pay in certain of the power sales agreements, including those signed
with the Company, were negotiated during a time when the power market was
dysfunctional and that they are unjust and unreasonable. The Company considers
the complaint to be without merit and is vigorously defending against it.
Emissions Credits Lawsuit. As described in previous reports, on March 5,
2002, the Company sued Automated Credit Exchange ("ACE") in the Superior Court
of the State of California for the County of Alameda for negligence and breach
of contract to recover reclaim trading credits, a form of emission reduction
credits that should have been held in the Company's account with U.S. Trust
Company ("US Trust"). the Company and ACE entered into a settlement agreement on
March 29, 2002, pursuant to which ACE made a payment to the Company of $7
million and transferred to the Company the rights to the emission reduction
credits to be held by ACE. The Company dismissed its complaint against ACE. The
Company recognized the $7 million 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 the the Company'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. InterGen's complaint refers to the payment by ACE of $7 million
to the Company, alleging that InterGen's ability to recover from EonXchange has
been undermined thereby. The Company is unable to assess the likelihood of
InterGen's complaint being upheld at this time.
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 the
Company's financial position or results of operations.
14. Operating Segments
The Company's primary operating segments are electric generation and
marketing; oil and gas production and marketing; and corporate activities and
other. Electric generation and marketing includes the development, acquisition,
ownership and operation of power production facilities, the sale of electricity
and steam and electricity hedging, balancing, optimization and trading activity.
Oil and gas production and marketing includes the ownership and operation of gas
fields, gathering systems and gas pipelines for internal gas consumption, third
party sales and oil and gas hedging, balancing, optimization and trading
activity. Corporate activities and other consists primarily of financing
activities, general and administrative costs and consolidating eliminations.
Certain costs related to company-wide functions are allocated to each segment.
However, interest on corporate debt is maintained at corporate and is not
allocated to the segments. Due to the integrated nature of the business
segments, estimates and judgments have been made in allocating certain revenue
and expense items. The Company evaluates performance of these operating segments
based upon several criteria including profits before tax.
Electric Oil and Gas
Generation Production Corporate, Other
and Marketing and Marketing and Eliminations Total
---------------------- ------------------ -------------------- ----------------------
2002 2001 2002 2001 2002 2001 2002 2001
---------- ---------- -------- -------- --------- -------- ---------- ----------
(in thousands)
For the three months
ended June 30, 2002 and 2001:
Revenue............................ $1,582,351 $1,261,705 $494,831 $381,983 $(135,376) $(30,815) $1,941,806 $1,612,873
Income (loss) before taxes and
extraordinary charge.............. 77,263 167,518 59,801 55,278 (28,989) (43,982) 108,075 178,814
Merger expense..................... -- -- -- 35,606 -- -- -- 35,606
Electric Oil and Gas
Generation Production Corporate, Other
and Marketing and Marketing and Eliminations Total
---------------------- ------------------ -------------------- ----------------------
2002 2001 2002 2001 2002 2001 2002 2001
---------- ---------- -------- -------- --------- -------- ---------- ----------
(in thousands)
For the six months
ended June 30, 2002 and 2001:
Revenue............................ $3,116,494 $2,312,334 $731,179 $713,811 $(167,520) $(73,521) $3,680,153 $2,952,624
Income (loss) before taxes and
extraordinary charge.............. 31,077 295,309 72,865 171,813 (113,401) (80,700) (9,459) 386,422
Merger expense..................... -- -- -- 41,627 -- -- -- 41,627
Equipment cancellation cost........ 168,471 -- -- -- -- -- 168,471 --
-24-
Electric Oil and Gas
Generation Production Corporate, Other
and Marketing and Marketing and Eliminations Total
------------- ------------- ---------------- -----------
(in thousands)
Total assets:
June 30, 2002.................................... $14,040,562 $3,706,453 $4,482,721 $22,229,736
December 31, 2001................................ $12,572,848 $3,503,075 $5,253,629 $21,329,552
For the three months ended June 30, 2002 and 2001, there were intersegment
revenues of approximately $140.6 million and $39.0 million, respectively. For
the six months ended June 30, 2002 and 2001, there were intersegment revenues of
approximately $177.3 million and $84.9 million, respectively. The elimination of
these intersegment revenues, which primarily relate to the use of internally
procured gas for the Company's power plants, are included in the Corporate and
Other reporting segment.
15. California Power Market
On April 22, 2002, the Company announced that it had renegotiated CES' long-term
power contracts with DWR. The Office of the Governor of California, the
California Public Utilities Commission (the "CPUC"), the California Electricity
Oversight Board (the "EOB") and the California Attorney General (the "AG")
endorsed the renegotiated contracts and agreed to drop all pending claims
against the Company and its affiliates, including withdrawing the complaint
under Section 206 of the Federal Power Act that had been filed by the CPUC and
EOB with FERC, and the termination by the CPUC and the EOB of their efforts to
seek refunds from the Company and its affiliates through FERC refund
proceedings. In connection with the renegotiation, the Company has agreed to pay
$6 million over three years to the AG to resolve any and all possible claims
against the Company and its affiliates brought by the AG.
CES had signed three long-term contracts with DWR in February 2001,
comprising two 10-year baseload energy contracts and one 20-year peaking
contract. The renegotiation provided for the shortening of the duration of each
of the two 10-year, baseload energy contracts by two years and of the 20-year
peaker contract by ten years. These changes reduced DWR's long-term purchase
obligations. In addition, CES agreed to reduce the energy price on one baseload
contract from $61.00 to $59.60 per megawatt-hour, and to convert the energy
portion of the peaker contract to gas index pricing from fixed energy pricing.
CES also agreed to deliver up to 12.2 million megawatt-hours of additional
energy pursuant to the baseload energy contracts in 2002 and 2003. In connection
with the renegotiation, CES also agreed with DWR that DWR will have the right to
assume and complete four of the Company's projects currently planned for
California and in the advanced development stage if the Company does not meet
certain milestones with respect to each project assumed, provided that DWR
reimburses the Company for all construction costs and certain other costs
incurred by the Company to the date DWR assumes the relevant project.
In addition, the negotiation resolved the dispute with DWR concerning
payment of the capacity payment on the peaking contract. The contract provides
that through December 31, 2002, CES may earn a capacity payment by committing to
supply electricity to DWR from a source other than the peaker units designated
in the contract. DWR had made certain assertions challenging CES' right to
substitute units or provide replacement energy and had withheld capacity
payments in the amount of approximately $15.0 million since December 2001. As
part of the renegotiation, the Company has received payment in full on these
withheld capacity payments and will have the right to provide replacement
capacity through December 31, 2002, on the original contract terms. On May 2,
2002, each of the CPUC and the EOB filed a Notice of Partial Withdrawal with
Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC.
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
In addition to historical information, this report contains forward-looking
statements. Such statements include those concerning Calpine Corporation's ("the
Company's") expected financial performance and its 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 involve a number of
risks and uncertainties that could cause actual results to differ materially
from the forward-looking statements such as, but 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 (iii) commercial operations of new plants that may be delayed or
prevented because of various development and construction risks, such as a
failure to obtain the necessary permits to operate, failure of third-party
-25-
contractors to perform their contractual obligations or failure to obtain
financing on acceptable terms (iv) unscheduled outages of operating plants (v)
unseasonable weather patterns that produce reduced demand for power (vi)
systemic economic slowdowns, which can adversely affect consumption of power by
businesses and consumers (vii) cost estimates are preliminary and actual costs
may be higher than estimated (viii) a competitor's development of lower-cost
generating gas-fired power plants (ix) risks associated with marketing and
selling power from power plants in the newly-competitive energy market (x) the
successful exploitation of an oil or gas resource that ultimately depends upon
the geology of the resource, the total amount and costs to develop recoverable
reserves and operations factors relating to the extraction of natural gas (xi)
the effects on the Company's business resulting from reduced liquidity in the
trading and power industry (xii) the Company's ability to access the capital
markets on attractive terms (xiii) sources and uses of cash are estimates based
on current expectations; actual sources may be lower and actual uses may be
higher than estimated (xiv) the direct or indirect effects on the Company's
business of a lowering of its credit rating (or actions it may take in response
to changing credit rating criteria), including, increased collateral
requirements, refusal by the Company's current or potential counterparties to
enter into transactions with it and its inability to obtain credit or capital in
desired amounts or on favorable terms. All information set forth in this filing
is as of August 9, 2002, and Calpine undertakes no duty to update this
information. Readers should carefully review the "Risk Factors" section in
documents filed with the Securities and Exchange Commission.
We file annual, quarterly and special 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 rooms in Washington, D.C., Chicago, Illinois
and New York, New York. 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. Our SEC filings are also accessible through the Internet at the
SEC's website at http://www.sec.gov.
Our reports on Forms 10-K, 10-Q and 8-K are available for download, free of
charge, as soon as reasonably practicable, 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 these 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 and steam fields, for which results are consolidated in our statements of
operations. Results vary for the three and six months ended June 30, 2002, as
compared to the same periods in 2001, for the reasons discussed more fully
throughout this Management's Discussion and Analysis of Financial Condition and
Results 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 revenue includes, 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 thermal sales and other revenue (revenues in thousands).
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- ------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(in thousands, except production and pricing data)
Power Plants:
Electricity and steam ("E&S") revenue:
Energy................................................. $ 409,415 $ 345,960 $ 922,519 $ 781,341
Capacity............................................... 257,107 127,595 332,497 245,323
Thermal and other...................................... 42,230 32,156 73,915 74,206
------------ ------------ ------------ ------------
Subtotal............................................. $ 708,752 $ 505,711 $ 1,328,931 $ 1,100,870
Spread on sales of purchased power (1).................... 169,611 26,801 262,750 25,453
------------ ------------ ------------ ------------
Adjusted E&S revenues..................................... $ 878,363 $ 532,512 $ 1,591,681 $ 1,126,323
Megawatt hours produced................................... 15,720,000 7,878,000 30,434,000 15,117,000
All-in electricity price per megawatt hour generated...... $ 55.88 $ 67.59 $ 52.30 $ 74.51
- ---------
(1) From hedging, balancing and optimization activities related to our
generating assets. The spread on trading activities is excluded.
-26-
Credit restrictions on certain Calpine Energy Services, L.P. ("CES")
activities in 2002 could negatively impact the volume of hedging, balancing and
optimization activities in the future.
Megawatt hours produced at the power plants increased 100% and 101% for the
three and six months ended June 30, 2002, as compared to the same periods in
2001. This was primarily due to the addition of power plants that were either
acquired or commenced commercial operation subsequent to June 30, 2001. The
decrease in average all-in electricity price per megawatt hour generated in 2002
reflects the softening market conditions in 2002 for power. The information
above is related to our generating assets and excludes trading activities which
are discussed in the Results of Operations and Performance Metrics below.
The increase in electricity and steam revenues due to the addition of power
plants was moderated by the reduction in CES's trading activities due to current
market conditions. However, we will evaluate alternatives as they are identified
for relationships with potential partners to strengthen our ability to conduct
risk management activities and to support the credit requirements of its trading
activities, but will proceed only if any such arrangement adds value to us.
Results of Operations
Set forth below is a table summarizing the dollar amounts and percentages
of our total revenue for the three and six months ended June 30, 2002 and 2001,
that represent purchased power and purchased gas sales and the costs we incurred
to purchase the power and gas that we resold during these periods (in thousands,
except percentage data):
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- ------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Total revenue................................................. $ 1,941,806 $ 1,612,873 $ 3,680,153 $ 2,952,624
Sales of purchased power...................................... 868,606 683,196 1,776,907 1,136,798
As a percentage of total revenue.............................. 44.7% 42.4% 48.3% 38.5%
Sales of purchased gas........................................ 302,044 226,693 434,202 355,865
As a percentage of total revenue.............................. 15.6% 14.1% 11.8% 12.1%
Total cost of revenue ("COR")................................. 1,685,500 1,308,648 3,245,883 2,372,831
Purchased power expense....................................... 698,176 655,322 1,513,181 1,111,588
As a percentage of total COR.................................. 41.4% 50.1% 46.6% 46.8%
Purchased gas expense......................................... 333,724 218,330 457,418 336,958
As a percentage of total COR.................................. 19.8% 16.7% 14.1% 14.2%
The accounting requirements under Staff Accounting Bulletin ("SAB") 101,
"Revenue Recognition in Financial Statements" and Emerging Issues Task Force
("EITF") Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as
an Agent" require us to show most of our hedging contracts on a gross basis (as
opposed to netting sales and cost of revenue). The primary reason for the
significant increase in these sales and cost of revenue in 2002 as compared with
2001 is the growth of our generation activity in 2002 as compared with 2001 and
the corresponding increase in hedging, balancing, optimization, and trading
activities.
Rules in effect throughout 2002 and 2001 associated with the NEPOOL market
in New England 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 in the
United States of America require 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. This gross basis presentation increases revenues but not
gross profit. The table below details the financial extent of our transactions
with NEPOOL for the period indicated. The decrease in 2002 is primarily due to
lower prices in 2002, partially offset by increased volume.
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- ------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(in thousands)
Sales into NEPOOL ISO from power we generated................ $ 63,455 $ 61,892 $ 114,036 $ 121,456
Sales into NEPOOL ISO from hedging and other activity........ 20,148 21,688 44,805 56,644
--------- --------- ---------- ----------
Total sales into NEPOOL ISO............................... $ 83,603 $ 83,580 $ 158,841 $ 178,100
Total purchases from NEPOOL ISO........................... $ 85,344 $ 81,317 $ 161,178 $ 166,560
-27-
Three Months Ended June 30, 2002, Compared to Three Months Ended June 30, 2001.
Revenue -- Total revenue increased to $1,941.8 million for the three months
ended June 30, 2002, compared to $1,612.9 million for the same period in 2001.
Electric generation and marketing revenue increased to $1,583.5 million in
2002 compared to $1,257.3 million in 2001. Approximately $203.0 million of the
$326.1 million variance was due to electricity and steam sales, which increased
due to our growing portfolio of power plants. Generation almost doubled but
average pricing dropped by 17%, moderating revenue growth. Our revenue for the
period ended June 30, 2002, includes the consolidated results of additional
facilities that we acquired or completed construction on subsequent to June 30,
2001. Sales of purchased power grew by $185.4 million due to increased price
hedging, balancing and optimization activity around our operating plant
portfolio during the three months ended June 30, 2002. This was offset by a
$62.3 million decrease in electric power derivative mark-to-market gain. In the
three months ended June 30, 2001, we recognized a significant mark-to-market
gain from power contracts in a market area where we did not have generation
assets. Due to industry-wide credit restrictions on risk management and trading
activities in 2002, such opportunities and other trading activities have been
greatly restricted.
Oil and gas production and marketing revenue increased to $354.2 million in
2002 compared to $343.0 million in 2001. The increase is due to a $75.4 million
increase in sales of purchased gas, offset by a $64.2 million decrease in oil
and gas sales to third parties primarily because of much lower average natural
gas pricing in 2002.
Cost of revenue -- Cost of revenue increased to $1,685.5 million in 2002
compared to $1,308.6 million in 2001. Approximately $42.9 million and $115.4
million of the $376.9 million increase relates to the cost of power and gas
purchased by our energy services organization, respectively, due to increased
price hedging, balancing, optimization and trading activities. Fuel expense
increased 55%, from $228.4 million in 2001 to $354.1 million in 2002, due to an
increase of 122% in gas-fired megawatt hours generated as offset by
significantly lower gas prices in 2002 and an improvement in average heat rate
of our generation portfolio. Plant operating expense increased by 71.7% from
$69.3 million to $118.9 million but, expressed per MWh of generation, decreased
from $8.79/MWh to $7.57/MWh as economies of scale are being realized due to the
increase in the average size of our plants. Depreciation, depletion and
amortization expense increased by 52.6%, from $72.1 million to $110.1 million,
due primarily to additional power facilities in consolidated operations at June
30, 2002, as compared to the same period in 2001.
Project development expense -- Project development expense increased $20.3
million as we expensed $18.1 million in costs related to the cancellation or
indefinite suspension of certain development projects.
Merger expense -- The merger expense of $35.6 million in the three months
ended June 30, 2001 was a result of the pooling-of-interests transaction with
Encal Energy Ltd.
Interest expense -- Interest expense increased 54.8% to $67.1 million for
the three months ended June 30, 2002, from $43.3 million for the same period in
2001. Interest expense increased primarily due to the issuance of the
Convertible Senior Notes Due 2006 and additional senior notes in the second half
of 2001 and due to the fact that interest expense on construction projects stops
being capitalized once the project goes into commercial operations and a greater
number of projects went into commercial operation in the three months ended June
30, 2002, than in the three months ended June 30, 2001. Interest capitalized
increased from $115.6 million in the three months ended June 30, 2001 to $171.0
million in the three months ended June 30, 2002, as a consequence of a larger
construction portfolio in 2002. We expect that interest expense will increase
and the amount of interest capitalized will decrease in the future as our plants
in construction are completed, and also as a result of the current suspension of
our development projects.
Interest income -- Interest income decreased to $9.8 million for the three
months ended June 30, 2002, compared to $20.5 million for the same period in
2001. This decrease is due primarily to lower cash balances and interest rates
in 2002.
Other income -- Other income declined by $0.5 million in the three months
ended June 30, 2002, compared to the same period in 2001. In the 2002 period we
recognized $7.0 million of recovery from ACE for losses incurred on reclaim
trading credit transactions (see Note 13 to the financial statements), and
additionally, we recognized gains from asset sales of $7.6 million. However,
these gains were partially offset by letter of credit fees of $6.2 million, $3.4
million for cost of a forfeited deposit on an asset purchase that did not close,
foreign exchange translation losses of $2.0 million, due primarily to weakening
in the Canadian dollar, and minority interest expense of $0.9 million. In the
corresponding period in 2001, we had a foreign exchange translation gain of $3.0
million.
-28-
Provision for income taxes -- The effective income tax rate was
approximately 32.9% and 39.1% for the three months ended June 30, 2002 and 2001,
respectively. The decrease in rates was due to our expansion into Canada and the
United Kingdom and our cross border financings, which reduced our effective
blended tax rates and due to the reversal of $2.6 million of a specific tax
reserve in 2002.
Extraordinary loss, net -- The $1.3 million charge (net of tax of $0.8
million) in the three months ended June 30, 2001 related to the write off of
unamortized deferred financing costs as a result of the repayment of the $105
million 9 1/4% Senior Notes Due 2004.
Six Months Ended June 30, 2002, Compared to Six Months Ended June 30, 2001.
Revenue -- Total revenue increased to $3,680.2 million for the six months
ended June 30, 2002, compared to $2,952.6 million for the same period in 2001.
Electric generation and marketing revenue increased to $3,116.1 million in
2002 compared to $2,307.4 million in 2001. Sales of purchased power grew by
$640.1 million due to increased price hedging, balancing and optimization
activity around our operating plant portfolio during the six months ended June
30, 2002. Approximately $228.1 million of the variance was due to electricity
and steam sales, which increased due to our growing portfolio of power plants.
Generation more than doubled, but average pricing dropped by 30% to moderate
revenue growth. Our revenue for the period ended June 30, 2002, includes the
consolidated results of additional facilities that we acquired or completed
construction on subsequent to June 30, 2001. The increase in electric generation
and marketing revenue was offset by a $59.5 million decrease in electric power
derivative mark-to-market gain. In the six months ended June 30, 2001, we
recognized a significant mark-to-market gain from power contracts in a market
area where we did not have generation assets. Due to industry-wide credit
restrictions on risk management and trading activities in 2002, such
opportunities and other trading activities have been greatly restricted.
Oil and gas production and marketing revenue decreased to $553.9 million in
2002 compared to $628.9 million in 2001. The decrease is primarily due to a
$153.4 million decrease in oil and gas sales to third parties because of much
lower average natural gas pricing in 2002, offset by a $78.3 million increase in
the sales of purchased gas.
Cost of revenue -- Cost of revenue increased to $3,245.9 million in 2002
compared to $2,372.8 million in 2001. Approximately $401.6 million and $120.5
million of the $873.1 million increase relates to the cost of power and gas
purchased by our energy services organization, respectively due to increased
price hedging, balancing, optimization and trading activities. Fuel expense
increased 41.5%, from $485.4 million in 2001 to $686.9 million in 2002, due to a
127% increase in gas-fired megawatt hours generated as offset by significantly
lower gas prices and an improved average heat rate of our generation portfolio
in 2002. Plant operating expense increased by 52.3% from $153.7 million to
$234.1 million but, expressed per MWh of generation, decreased from $10.17/MWh
to $7.69/MWh as economies of scale are being realized due to the increase in the
average size of our plants. Royalty expense decreased $9.6 million between
periods due to a decrease in revenue for The Geysers geothermal plants.
Depreciation, depletion and amortization expense increased by 48.4%, from $144.2
million to $214.0 million, due primarily to additional power facilities in
consolidated operations at June 30, 2002, as compared to the same period in
2001. Operating lease expense increased 30.5% between periods due to
sale/leaseback transactions subsequent to June 30, 2001.
Project development expense -- Project development expense increased 78.4%
as we expensed $22.3 million in costs related to the cancellation or indefinite
suspension of certain development projects.
Equipment cancellation cost -- The pre-tax equipment cancellation charge of
$168.5 million in the six months ended June 30, 2002, was as a result of the
turbine order cancellations and the cancellation of certain other equipment
based primarily on forfeited prepayments to date.
General and administrative expense -- General and administrative expense
increased 31.4% to $113.9 million for the six months ended June 30, 2002, as
compared to $86.6 million for the same period in 2001. The increase was
attributable to continued growth in personnel and associated overhead costs
necessary to support the overall growth in our operations and due to recent
acquisitions, including power facilities and natural gas operations. General and
administrative expense expressed per MWh of generation decreased to $3.74/MWh in
2002 from $5.73/MWh in 2001.
Merger expense -- The merger expense of $41.6 million in the six months
ended June 30, 2001 was a result of the pooling-of-interests transaction with
Encal Energy Ltd.
Interest expense -- Interest expense increased 102.9% to $128.4 million for
the six months ended June 30, 2002, from $63.3 million for the same period in
2001. Interest expense increased primarily due to the issuance of the
-29-
Convertible Senior Notes Due 2006 and additional senior notes in the second
half of 2001 and due to the new plants going into commercial operations at which
point capitalization of interest expense ceases. Interest capitalized increased
from $219.6 million in the six months ended June 30, 2001 to $334.1 million in
the six months ended June 30, 2002, due to a larger construction portfolio in
2002. We expect that interest expense will continue to increase and the amount
of interest capitalized will decrease in future periods as our plants in
construction are completed, and also as a result of the current suspension of
our development projects.
Interest income -- Interest income decreased to $21.9 million for the six
months ended June 30, 2002, compared to $39.9 million for the same period in
2001. This decrease is due primarily to lower cash balances and interest rates
in 2002.
Other income -- Other income increased by $2.8 million in the six months
ended June 30, 2002, compared to the same period in 2001. In the 2002 period we
recognized $7.0 million of recovery from ACE for losses incurred on reclaim
trading credit transactions (see Note 13 to the financial statements), and
additionally, we recognized net gains from asset sales of $18.8 million, which
was primarily due to a gain of $9.7 million from the sale of our interests in
the Lockport project, gains of $4.3 million from sales of non-strategic Canadian
properties, and a gain of $2.7 million from the sale of our 7.5% interest in the
Bayonne project. However, these gains were partially offset by letter of credit
fees of $6.2 million, $3.4 million for cost of a forfeited deposit on an asset
purchase that did not close, foreign exchange translation losses of $2.2 million
and minority interest expense of $0.9 million. In the corresponding period in
2001, we had gains on sales of assets of $12.7 million, primarily from a $7.2
million gain on the sale of our development interests in the Elwood project and
a gain of $4.9 million from the sale of our 7.5% interest in the Bayonne
project, which was partially offset by a foreign exchange translation loss of
$2.4 million, due primarily to weakening in the Canadian dollar.
Provision for income taxes -- The effective income tax rate was
approximately 59.0% and 41.1% for the six months ended June 30, 2002 and 2001,
respectively. The increase is not meaningful since the 2002 effective rate
reflects the reversal of $2.6 million of specific tax reserve in 2002 and is
applied to a small net loss.
Extraordinary gain (loss), net -- The $2.1 million gain (net of tax of $1.4
million) in 2002 represents the repurchase of $192.5 million aggregate principal
amount of our Zero Coupon Convertible Debentures Due 2021 ("Zero Coupons"),
which was comprised primarily of a $4.8 million gain from the repurchase of the
Zero Coupons at a discount, partially offset by a loss due to the write-off of
unamortized deferred financing costs. The $1.3 million charge (net of tax of
$0.8 million) in 2001 related to the write off of unamortized deferred financing
costs as a result of the repayment of the $105 million 9 1/4% Senior Notes Due
2004.
Cumulative effect of a change in accounting principle - In 2001 the $1.0
million of additional income (net of tax of $0.7 million), is due to the
adoption of Financial Accounting Standards Board ("FASB") Statement of Financial
Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended by SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133 - an Amendment of FASB Statement No. 133," and as further
amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities - an Amendment of FASB Statement No. 133."
Selected Balance Sheet Information
Unconsolidated Investments in Power Projects -- Although our preference is
to own 100% of the power plants we acquire or develop, there are situations when
we take less than 100% ownership. Reasons why we may take less than a 100%
interest in a power plant may include, but are not limited to: (a) our
acquisitions of other IPPs such as Cogeneration Corporation of America in 1999
and SkyGen Energy LLC in 2000 in which minority interest projects were included
in the portfolio of assets owned by the acquired entities (Grays Ferry Power
Plant (40% now owned by Calpine) and Androscoggin Energy Center (32.3% now owned
by Calpine); (b) opportunities to co-invest with non-regulated subsidiaries of
regulated electric utilities, which under the Public Utility Regulatory Policies
Act of 1978, as amended are restricted to 50% ownership of cogeneration
qualifying facilities -- such as our investment in Gordonsville Power Plant (50%
owned by Calpine and 50% owned by Edison Mission Energy, which is wholly-owned
by Edison International Company); and (c) opportunities to invest in merchant
power projects with partners who bring marketing, funding, permitting or other
resources that add value to a project. An example of this is Acadia Energy
Center, which is under construction in Louisiana (50% owned by Calpine and 50%
owned by Cleco Midstream Resources, an affiliate of Cleco Corporation). None of
our equity investment projects have nominal carrying values as a result of
material recurring losses. Further, there is no history of impairment in any of
these investments.
-30-
Accumulated other comprehensive loss -- The amount of the accumulated other
comprehensive loss decreased from $(226.6) million at December 31, 2001, to
$(118.7) million at June 30, 2002. The change resulted from unrealized gains on
derivatives designated as cash flow hedges of $54.3 million, net of amounts
reclassified to net loss and income taxes, and foreign currency translation gain
of $53.6 million. See Note 9 for further information.
Liquidity and Capital Resources
General -- The latter half of 2001, and particularly the fourth quarter,
saw the beginning of a significant contraction in the availability of capital
for participants in the energy sector. This was due to a range of factors,
including uncertainty arising from the collapse of Enron and a perceived near
term surplus supply of electric generating capacity. While we have been able to
access the capital and bank credit markets, as discussed below, we recognize
that terms of financing available to us now and in the future may not be
attractive to us. To protect against this possibility, we have scaled back our
capital expenditure program for 2002 and 2003 to enable us to conserve our
available capital resources, but remain ready to access the capital markets as
attractive opportunities arise.
To date, we have obtained cash from our operations; borrowings under our
facilities and other working capital lines; sale of debt, equity, trust
preferred securities and convertible debentures; proceeds from sale/leaseback
transactions, sale of non-strategic assets and project financing. We have
utilized this cash to fund our operations, service 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 business is
capital intensive. Our ability to capitalize on growth opportunities is
dependent on the availability of capital on attractive terms; the timing of the
availability of such capital in today's environment is uncertain. Our strategy
is also to reinvest our cash from operations into our business development and
construction program, rather than to pay cash dividends.
Factors that could affect our liquidity and capital resources are also
discussed in the "Risk Factors" section of our Annual Report on Form 10-K for
the year ended December 31, 2001.
Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Six Months Ended June 30,
------------------------------
2002 2001
------------ ------------
(in thousands)
Beginning cash and cash equivalents........................................... $ 1,525,417 $ 596,077
Net cash provided by (used in):
Operating activities....................................................... 463,445 89,973
Investing activities....................................................... (2,558,322) (2,772,635)
Financing activities....................................................... 1,094,269 3,328,105
Effect of exchange rates changes on cash and cash equivalents.............. 3,958 --
------------ ------------
Net increase (decrease) in cash and cash equivalents....................... (996,650) 645,443
------------ ------------
Ending cash and cash equivalents........................................ $ 528,767 $ 1,241,520
============ ============
Operating activities for the six months ended June 30, 2002, provided net
cash of $463.4 million, compared to $90.0 million for the six months ended June
30, 2001. The cash provided by operating activities for the six months ended
June 30, 2002, consisted of a $227.5 million decrease in operating assets,
primarily relating to a $236.2 million decrease in margin deposits and other
prepaid expenses. This was offset by a $355.1 million decrease in operating
liabilities, primarily related to derivative activity. A primary factor causing
the significant increase in cash flow from operations in the six months ended
June 30, 2002, in comparison to the same period in 2001, is the realization of
over $200 million of pre-bankruptcy petition PG&E receivables in the first
quarter of 2002, which helped our operating cash flow performance and,
similarly, the failure to collect those receivables in the first half of 2001,
which reduced operating cash flow in that period.
Investing activities for the six months ended June 30, 2002, consumed net
cash of $2.6 billion, primarily due to $2.5 billion for construction costs and
capital expenditures including gas turbine generator costs and associated
capitalized interest, $43.8 million of advances to joint ventures including
associated capitalized interest for investments in power projects under
construction, $63.7 million of capitalized project development costs including
associated capitalized interest, and a $27.8 million increase in restricted
cash. This was partially offset by a $49.8 million of proceeds on sales of
property, plant and equipment and investments in power projects.
-31-
Financing activities for the six months ended June 30, 2002, provided $1.1
billion of net cash consisting of $751.2 million of proceeds from the offering
of common stock, $100.0 million of proceeds from the issuance of additional
Convertible Senior Notes Due 2006 pursuant to exercise of the initial
purchasers' remaining purchase option, $1.1 billion of proceeds from drawings on
our term loan and revolving lines of credit, and $280.2 million of proceeds from
project financing. This was partially offset by $873.2 million for the
repurchase of the outstanding Zero Coupons, $87.5 million for the repayment of
notes payable and borrowings under our lines of credit, $92.2 million for
repayments of project financing and $59.9 million of additional financing costs.
We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit, access to the sale/leaseback and other
markets, sale of non-strategic assets and cash balances to satisfy all
obligations under outstanding indebtedness, to finance anticipated capital
expenditures and to fund working capital requirements for the next twelve
months.
Enron Bankruptcy -- We believe, based on legal analysis, that we have no
net collection exposure to Enron. See Note 10 to the Consolidated Condensed
Financial Statements.
Nevada Power and Sierra Pacific Power Company -- During the first quarter
of 2002, two subsidiaries of Sierra Pacific Resources Company, Nevada Power
Company ("NPC") and Sierra Pacific Power Company ("SPPC"), received credit
downgrades to sub-investment grades from the major credit rating agencies.
Additionally, NPC acknowledged liquidity problems created when the Public
Utilities Commission of Nevada disallowed a rate adjustment requested by NPC to
cover the increased cost of buying power during the 2001 energy crisis. NPC has
requested that its power suppliers extend payment terms to help it overcome its
short-term liquidity problems. During the second quarter of 2002, NPC indicated
to its power suppliers that it was experiencing cash flow difficulties. In June
and July 2002 NPC underpaid us by approximately $4.2 million, and we expect that
NPC will underpay us by approximately an additional $18.4 million this summer
and early fall. In consideration of the uncertainty surrounding NPC's ability to
make timely payments, we are maintaining a bad debt reserve of approximately
$2.7 million against NPC receivables. See Part II -- Other Information - Item 1
for further discussion.
As of June 30, 2002, we had net collection exposures of approximately $34.8
million and $20.2 million with NPC and SPPC, respectively. However, SPPC is
paying us currently. Our exposures include open forward power contracts that are
reported at fair value on our balance sheet as well as receivable and payable
balances relating to prior power deliveries. We are continuing to monitor our
exposure and its effect on our financial condition.
PSM License Receivable -- In December 2001 PSM and a Dutch power services
company entered into a perpetual world-wide license agreement for certain PSM
proprietary reverse-flow venturi technology. The license fee, while earned
upfront, is payable over the period from January 2002 through March 2004. The
Company recognized the license fee of $11 million (less imputed interest on the
receivable) as income in December 2001. As of the date of this filing, we have a
receivable of $7 million, with no payments currently past due. The indirect
parent of the Dutch company, a German holding company, filed for insolvency in
Germany in July 2002 and the direct parent of the Dutch company is expected to
also file for insolvency. However, the Dutch company has assured us that it
has not and currently does not expect to file for insolvency in the near term.
We have been further assured in a letter from the German holding company dated
July 11, 2002, that the Dutch company expects to continue the license
arrangement and to meet its obligations thereunder. Based on our evaluation of
these and other factors, a loss does not seem probable at this time.
Accordingly, we have not established a reserve against the related receivable
but will continue to closely monitor the situation.
CES Margin Deposits and Other Credit Support -- As of June 30, 2002, CES
had $67.3 million in cash on deposit as margin deposits with third parties
related to its business activities and letters of credit outstanding in support
of CES business activities of $315.0 million. As of December 31, 2001, CES had
deposited $345.5 million in cash as margin deposits with third parties related
to its business activities and letters of credit outstanding in support of CES
business activities of $259.4 million. While we believe that we have adequate
liquidity to support CES' 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.
Revised Capital Expenditure Program -- Following a comprehensive review of
our power plant development program, we announced in January 2002 the adoption
of a revised capital expenditure program, which contemplated the completion of
27 power projects (representing 15,200 MW) then under construction. Nine of
these facilities have subsequently achieved full or partial commercial operation
as of June 30, 2002. Construction of advanced stage development projects is
-32-
expected to proceed only when there is an established market need for additional
generating resources at prices that will allow us to meet our established
investment criteria, and when capital may again become available to us on
attractive terms. Further, our entire development and construction program is
flexible and subject to continuing review and revision based upon such criteria.
On March 12, 2002, we announced a new turbine program that reduces
previously forecasted capital spending by approximately $1.2 billion in 2002 and
$1.8 billion in 2003. The revision includes adjusted timing of turbine delivery
and related payment schedules and also cancellation of some orders. As a result
of these turbine cancellations and other equipment cancellations, we recorded a
pre-tax charge of $168.5 million in the first quarter of 2002.
Uses and Sources of Funding -- As of August 1, 2002, our estimated uses of
funds for 2002 are as follows: construction costs of $2.6 billion, cost to
repurchase the remaining Zero Coupons of $0.9 billion, other debt repayment
costs of $0.1 billion, maintenance and gas capital expenditures of $0.3 billion,
cash lease payments of $0.3 billion, estimated Enron contract settlement
payments of $0.1 billion and $0.7 billion for turbines for financeable and
future projects. These uses of funds will be funded primarily through an
estimated $0.8 billion of operating cash flow for 2002, $0.3 billion of CES cash
collateral replaced with letters of credit and cash on hand of $1.8 billion
(consists of cash on hand of $1.5 billion at December 31, 2001, $0.2 billion
from the sale of the PG&E receivables, $0.1 billion from the sale of Convertible
Senior Notes Due 2006 in early January 2002). The other sources of funding
include $1.0 billion from the two-year term loan, $0.7 billion from the April
equity offering, $0.6 billion from our construction revolvers and our proposed
California peaker leases, as well as $0.3 billion from our secured revolving
credit facilities. We are also negotiating the sale of non-strategic assets for
approximately $0.3 billion. Other potential sources of cash include monetizing
our Canadian power generation assets for approximately $0.3 billion, entering
into a sale/leaseback transaction for our Zion facility for cash proceeds of
$0.2 billion, selling our Gilroy note receivable for $0.2 billion, selling
certain additional assets, including oil and gas properties, for proceeds net of
debt repayment of $0.4 billion, and financing for our future turbines of $0.3
billion. Actual costs for the projected uses of funds identified above, and net
proceeds from the projected sources of funds identified above could vary from
those estimates, potentially in material respects. Factors that could affect the
accuracy of these estimates are discussed in our Annual Report on Form 10-K for
the year ended December 31, 2001, in the "Risk Factors" section.
Capital Availability -- Notwithstanding recent uncertainties in the
domestic energy and capital markets, we raised substantial capital earlier in
2002. On April 30, 2002, we completed a public offering of common stock of 66
million shares and priced the offering at $11.50 per share. The proceeds after
underwriting fees totaled $734.3 million. The proceeds from the offering were
used to repay debt and for general corporate purposes.
On May 14, 2002, our subsidiary, Calpine California Energy Finance, LLC,
entered into an amended and restated credit agreement with ING Capital LLC for
the funding of 9 California peaker facilities, of which $100.0 million was drawn
on May 24, 2002. The total $100.0 million funding is classified as current
project financing, of which $50.0 million was repaid on August 7, 2002, and
$50.0 million will be payable on September 30, 2002. This peaker funding is part
of our expected long-term financing of our California peaker facilities which is
anticipated to be $500.0 million.
During the second quarter of 2002, we increased our two-year secured bank
term loan to $1.0 billion from $600 million, and reduced the size of our secured
corporate revolving credit facilities to $1.0 billion from $1.4 billion. At June
30, 2002, we had $1.0 billion in borrowings outstanding under the term loan
facility and $75.0 million in borrowings outstanding under the revolving credit
facility.
Letter of credit facilities -- At June 30, 2002, we had approximately
$874.6 million in letters of credit outstanding under various credit support
facilities, including facilities related to CES risk management activities, and
other operational and construction activities. Of the total letters of credit
outstanding, $723.2 million were issued under the corporate revolving credit
facilities. At December 31, 2001, we had $642.5 million in letters of credit
outstanding, including facilities relating to CES risk management activities.
Off-Balance Sheet Commitments -- In accordance with SFAS No. 13 and SFAS
No. 98, "Accounting for Leases" our operating leases are not reflected on our
balance sheet. We have also entered into sale/leaseback transactions involving
our Tiverton, Rumford, South Point, Broad River, and RockGen projects. All
counterparties in these transactions are third parties that are unrelated to us.
The sale/leaseback transactions utilize special-purpose entities formed by the
equity investors with the sole purpose of owning a power generation facility. We
have no ownership or other interest in any of these special-purpose entities.
Some of our operating leases contain customary restrictions on dividends,
additional debt and further encumbrances similar to those typically found in
project finance debt instruments.
-33-
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)," the debt on the books of our
unconsolidated investments in power projects is not reflected on our balance
sheet. At June 30, 2002, investee debt totaled $660.6 million. Based on our pro
rata ownership share of each of the investments, our share would be $244.8
million. However, all such debt is non-recourse to us. For the Aries Power Plant
construction debt, we and Aquila Energy, a wholly owned subsidiary of Aquila
Inc, have provided support arrangements until construction is completed to cover
cost overruns, if any. Additionally, one of our projects with an operating lease
has $237.8 million of debt outstanding at June 30, 2002.
Performance Metrics
In understanding our business, we believe that certain performance metrics
are particularly important. These include:
o Average gross profit margin based on pro forma (non-GAAP) revenue and
pro forma (non-GAAP) cost of revenue. A high percentage of our recent
revenue has consisted of CES hedging, balancing, optimization, and
trading activity undertaken primarily to enhance the value of our
generating assets (see "Marketing, Hedging, Optimization, and Trading"
subsection of the Business Section of our 2001 Form 10-K). CES's
hedging, balancing, optimization, and trading activity is primarily
accomplished by buying and selling electric power and buying and
selling natural gas or by entering into gas financial instruments such
as exchange-traded swaps or forward contracts. Under SAB No. 101 and
EITF No. 99-19, we must show the purchases and sales of electricity
and gas on a gross basis in our statement of operations when we act as
a principal, take title to the electricity and gas we purchase for
resale, and enjoy the risks and rewards of ownership. This is
notwithstanding the fact that the net gain or loss on certain
financial hedging instruments, such as exchange-traded natural gas
price swaps, is shown as a net item in our GAAP financials. Because of
the inflating effect on revenue of much of our hedging, balancing,
optimization, and trading activity, we believe that revenue levels and
trends do not reflect our performance as accurately as gross profit,
and that it is analytically useful to look at our results on a pro
forma, non-GAAP basis with all hedging, balancing, optimization, and
trading activity netted. This analytical approach nets the sales of
purchased power with purchased power expense (with the exception of
net realized sales and expenses on electrical trading activity, which
is shown on a net basis in sales of purchased power) and includes that
net amount as an adjustment to E&S revenue for our generation assets.
Similarly, we believe that it is analytically useful to net the sales
of purchased gas with purchased gas expense (with the exception of net
realized sales and expenses on gas trading activity, which is shown on
a net basis in sales of purchased gas) and include that net amount as
an adjustment to cost of oil and natural gas burned by power plants, a
component of fuel expense. This allows us to look at all hedging,
balancing, optimization, and trading activity consistently (net
presentation) and better understand our performance trends. It should
be noted that in this non-GAAP analytical approach, total gross profit
does not change from the GAAP presentation, but the gross profit
margins as a percent of revenue do differ from corresponding GAAP
amounts because the inflating effects on our revenue of hedging,
balancing, optimization, and trading activities are removed.
o Average availability and average 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
capacity factor, sometimes called operating rate, is calculated by
dividing (a) total megawatt hours generated by our power plants
(excluding peakers) by 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 capacity factor will reflect that
decision as well as both scheduled and unscheduled outages due to
maintenance and repair requirements.
o Average heat rate for gas-fired fleet of power plants expressed in
Btu's 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.
-34-
o Average all-in realized electric price expressed in dollars per MWh
generated. We calculate the all-in realized electric price per MWh
generated by dividing (a) adjusted E&S revenue, which includes
capacity revenues, energy revenues, thermal revenues and the spread on
sales of purchased electricity 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. At Calpine, 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
cost of oil and natural gas burned by power plants which includes the
cost of fuel consumed by our plants (adding back cost of intercompany
"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 cost of oil and
natural gas burned by power plants from (b) adjusted E&S revenue and
dividing the difference by (c) total generated MWh's in the period.
The table below presents, side-by-side, both our GAAP and pro forma
non-GAAP netted revenue, costs of revenue and gross profit showing the purchases
and sales of electricity and gas for hedging, balancing, optimization, and
trading activity on a net basis. It also shows the other performance metrics
discussed above.
Non-GAAP Netted
GAAP Presentation Presentation
Three Months Ended June 30, Three Months Ended June 30,
---------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Revenue, Cost of Revenue and Gross Profit
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue(1)....................... $ 708,752 $ 505,711 $ 878,363 $ 532,512
Sales of purchased power(1)............................ 868,606 683,196 819 1,073
Electric power derivative mark-to-market gain.......... 6,104 68,433 6,104 68,433
----------- ----------- ----------- -----------
Total electric generation and marketing revenue...... 1,583,462 1,257,340 885,286 602,018
Oil and gas production and marketing revenue
Oil and gas sales...................................... 52,163 116,319 52,163 116,319
Sales of purchased gas(1).............................. 302,044 226,693 1,383 1,715
----------- ----------- ----------- -----------
Total oil and gas production and marketing revenue... 354,207 343,012 53,546 118,034
Income (loss) from unconsolidated investments in
power projects........................................... (1,121) 1,600 (1,121) 1,600
Other revenue............................................. 5,258 10,921 5,258 10,921
----------- ----------- ----------- -----------
Total revenue..................................... 1,941,806 1,612,873 942,969 732,573
----------- ----------- ----------- -----------
(table continues)
-35-
(table continued)
Non-GAAP Netted
GAAP Presentation Presentation
Three Months Ended June 30, Three Months Ended June 30,
---------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Cost of revenue:
Electric generation and marketing expense
Plant operating expense................................ 118,930 69,259 118,930 69,259
Royalty expense........................................ 4,194 6,916 4,194 6,916
Purchased power expense(1)............................. 698,176 655,322 -- --
----------- ----------- ----------- -----------
Total electric generation and marketing expense...... 821,300 731,497 123,124 76,175
Oil and gas production and marketing expense
Oil and gas production expense......................... 27,836 27,308 27,836 27,308
Purchased gas expense(1)............................... 333,724 218,330 -- --
----------- ----------- ----------- -----------
Total oil and gas production and marketing expense... 361,560 245,638 27,836 27,308
Fuel expense
Cost of oil and natural gas burned by power plants(1).. 350,848 251,876 383,911 245,228
Natural gas derivative mark-to-market loss (gain)...... 3,203 (23,446) 3,203 (23,446)
----------- ----------- ----------- -----------
Total fuel expense................................... 354,051 228,430 387,114 221,782
Depreciation, depletion and amortization expense.......... 110,122 72,144 110,122 72,144
Operating lease expense................................... 36,263 27,449 36,263 27,449
Other expense............................................. 2,204 3,490 2,204 3,490
----------- ----------- ----------- -----------
Total cost of revenue............................. 1,685,500 1,308,648 686,663 428,348
----------- ----------- ----------- -----------
Gross profit................................................. $ 256,306 $ 304,225 $ 256,306 $ 304,225
=========== =========== =========== ===========
Gross profit margin.......................................... 13% 19% 27% 42%
Non-GAAP Netted
GAAP Presentation Presentation
Six Months Ended June 30, Six Months Ended June 30,
---------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Revenue, Cost of Revenue and Gross Profit
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue(1)....................... $ 1,328,931 $ 1,100,870 $ 1,591,681 $ 1,126,323
Sales of purchased power(1)............................ 1,776,907 1,136,798 976 (243)
Electric power derivative mark-to-market gain.......... 10,270 69,739 10,270 69,739
----------- ----------- ----------- -----------
Total electric generation and marketing revenue...... 3,116,108 2,307,407 1,602,927 1,195,819
Oil and gas production and marketing revenue
Oil and gas sales...................................... 119,651 273,006 119,651 273,006
Sales of purchased gas(1).............................. 434,202 355,865 7,455 4,884
----------- ----------- ----------- -----------
Total oil and gas production and marketing revenue... 553,853 628,871 127,106 277,890
Income from unconsolidated investments in
power projects........................................... 323 2,163 323 2,163
Other revenue............................................. 9,869 14,183 9,869 14,183
----------- ----------- ----------- -----------
Total revenue..................................... 3,680,153 2,952,624 1,740,225 1,490,055
----------- ----------- ----------- -----------
(table continues)
-36-
(table continued)
Non-GAAP Netted
GAAP Presentation Presentation
Six Months Ended June 30, Six Months Ended June 30,
---------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Cost of revenue:
Electric generation and marketing expense
Plant operating expense................................ 234,087 153,719 234,087 153,719
Royalty expense........................................ 8,349 17,925 8,349 17,925
Purchased power expense(1)............................. 1,513,181 1,111,588 -- --
----------- ----------- ----------- -----------
Total electric generation and marketing expense...... 1,755,617 1,283,232 242,436 171,644
Oil and gas production and marketing expense
Oil and gas production expense......................... 54,776 61,591 54,776 61,591
Purchased gas expense(1)............................... 457,418 336,958 -- --
----------- ----------- ----------- -----------
Total oil and gas production and marketing expense... 512,194 398,549 54,776 61,591
Fuel expense
Cost of oil and natural gas burned by power plants(1).. 677,291 516,439 707,962 502,416
Natural gas derivative mark-to-market loss (gain)...... 9,595 (30,995) 9,595 (30,995)
----------- ----------- ----------- -----------
Total fuel expense................................... 686,886 485,444 717,557 471,421
Depreciation, depletion and amortization expense.......... 213,995 144,157 213,995 144,157
Operating lease expense................................... 72,397 55,460 72,397 55,460
Other expense............................................. 4,794 5,989 4,794 5,989
----------- ----------- ----------- -----------
Total cost of revenue............................. 3,245,883 2,372,831 1,305,955 910,262
----------- ----------- ----------- -----------
Gross profit................................................. $ 434,270 $ 579,793 $ 434,270 $ 579,793
=========== =========== =========== ===========
Gross profit margin.......................................... 12% 20% 25% 39%
Non-GAAP Netted Non-GAAP Netted
Presentation Presentation
Three Months Ended June 30, Six Months Ended June 30,
---------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Other Non-GAAP Performance Metrics
Average availability and capacity factor:
Average availability...................................... 95% 91% 95% 91%
Average capacity factor or operating rate based on
total hours (excluding peakers).......................... 66% 65% 68% 67%
Average heat rate for gas-fired power plants (excluding
peakers) (Btu's/kWh):
Not steam adjusted........................................ 8,158 8,504 8,165 8,582
Steam adjusted............................................ 7,455 7,612 7,416 7,562
Average all-in realized electric price:
Adjusted electricity and steam revenue (in thousands)..... $ 878,363 $ 532,512 $ 1,591,681 $ 1,126,323
MWh generated (in thousands).............................. 15,720 7,878 30,434 15,117
Average all-in realized electric price per MWh............ $ 55.88 $ 67.59 $ 52.30 $ 74.51
Average cost of natural gas:
Cost of oil and natural gas burned by power plants
(in thousands)........................................... $ 383,911 $ 245,228 $ 707,962 $ 502,416
Fuel cost elimination..................................... 61,357 35,455 69,954 78,671
----------- ----------- ----------- -----------
Adjusted cost of oil and natural gas burned by
power plants............................................. $ 445,268 $ 280,683 $ 777,916 $ 581,087
MMBtu of fuel consumed by generating plants
(in thousands)........................................... 112,750 53,151 219,274 101,144
Average cost of natural gas per MMBtu..................... $ 3.95 $ 5.28 $ 3.55 $ 5.75
MWh generated (in thousands).............................. 15,720 7,878 30,434 15,117
Average cost of oil and natural gas burned by
power plants per MWh..................................... $ 28.32 $ 35.63 $ 25.56 $ 38.44
Average spark spread:
Adjusted electricity and steam revenue (in thousands)..... $ 878,363 $ 532,512 $ 1,591,681 $ 1,126,323
Less: Adjusted cost of oil and natural gas burned by
power plants (in thousands)........................... 445,268 280,683 777,916 581,087
----------- ----------- ----------- -----------
Spark spread (in thousands)............................... $ 433,095 $ 251,829 $ 813,765 $ 545,236
MWh generated (in thousands).............................. 15,720 7,878 30,434 15,117
Average spark spread per MWh.............................. $ 27.56 $ 31.97 $ 26.74 $ 36.07
The non-GAAP presentation above also facilitates a look at the total
"trading" activity impact on gross profit. For the three and six months ended
June 30, 2002 and 2001, trading activity consisted of (dollars in thousands):
-37-
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2002 2001 2002 2001
-------- -------- -------- --------
ELECTRICITY Electric generation and marketing revenue
Realized gain (loss) Sales of purchased power............................. $ 819 $ 1,073 $ 976 $ (243)
Unrealized Electric power derivative mark-to-market gain........ 6,104 68,433 10,270 69,739
-------- -------- -------- --------
Subtotal.................................................................. $ 6,923 $ 69,506 $ 11,246 $ 69,496
GAS Oil and gas production and marketing revenue
Realized gain (loss) Sales of purchased gas............................... $ 1,383 $ 1,715 $ 7,455 $ 4,884
Fuel Expense
Unrealized Natural gas derivative mark-to-market gain (loss).... (3,203) 23,446 (9,595) 30,995
-------- -------- -------- --------
Subtotal.................................................................. $ (1,820) $ 25,161 $ (2,140) $ 35,879
Three Months Three Months
Ended Percent of Ended Percent of
June 30, Gross June 30, Gross
2002 Profit 2001 Profit
------------ ---------- ------------ ----------
Total trading activity gain.................................................. $ 5,103 2.0% $ 94,667 31.1%
Realized gain (loss)......................................................... $ 2,202 0.9% $ 2,788 0.9%
Unrealized (mark-to-market) gain (loss)(2)................................... $ 2,901 1.1% $ 91,879 30.2%
Six Months Six Months
Ended Percent of Ended Percent of
June 30, Gross June 30, Gross
2002 Profit 2001 Profit
------------ ---------- ----------- ----------
Total trading activity gain.................................................. $ 9,106 2.1% $ 105,375 18.2%
Realized gain (loss)......................................................... $ 8,431 1.9% $ 4,641 0.8%
Unrealized (mark-to-market) gain (loss)(2)................................... $ 675 0.2% $ 100,734 17.4%
(1) Following is a reconciliation of GAAP to non-GAAP presentation further to
the narrative set forth under this Performance Metrics section ($ in
thousands):
(2) For the three and six months ended June 30, 2002, the mark-to-market
gains shown above as "trading" activity include a net loss on hedge
ineffectiveness of $(12) and $(2,829), consisting of an ineffectiveness loss on
power hedges of $(1,002) and $(1,224), an ineffectiveness gain (loss) on crude
oil costless collar arrangements of $711 and $(4,330) and an ineffectiveness
gain on gas hedges of $279 and $2,725. For the three and six months ended June
30, 2001, the mark-to-market gains shown above as "trading" activity include a
net loss on hedge ineffectiveness of $(2,781) and $(3,472), consisting of an
ineffectiveness gain on power hedges of $1,217 and $0 and an ineffectiveness
loss on gas hedges of $(3,998) and $(3,472).
To Net
Hedging,
Balancing & To Net Netted
GAAP Optimization Trading Non-GAAP
Balance Activity Activity Balance
----------- ------------ ---------- -----------
Three months ended June 30, 2002
Electricity and steam revenue............................. $ 708,752 $ 169,611 $ -- $ 878,363
Sales of purchased power.................................. 868,606 (856,876) (10,911) 819
Sales of purchased gas.................................... 302,044 (302,044) 1,383 1,383
Purchased power expense................................... 698,176 (687,265) (10,911) --
Purchased gas expense..................................... 333,724 (333,724) -- --
Cost of oil and natural gas burned by power plants........ 350,848 31,680 1,383 383,911
Three months ended June 30, 2001
Electricity and steam revenue............................. $ 505,711 $ 26,801 $ -- $ 532,512
Sales of purchased power.................................. 683,196 (578,230) (103,893) 1,073
Sales of purchased gas.................................... 226,693 (226,693) 1,715 1,715
Purchased power expense................................... 655,322 (551,429) (103,893) --
Purchased gas expense..................................... 218,330 (218,330) -- --
Cost of oil and natural gas burned by power plants........ 251,876 (8,363) 1,715 245,228
-38-
To Net
Hedging,
Balancing & To Net Netted
GAAP Optimization Trading Non-GAAP
Balance Activity Activity Balance
----------- ------------ ---------- -----------
Six months ended June 30, 2002
Electricity and steam revenue............................. $ 1,328,931 $ 262,750 $ -- $ 1,591,681
Sales of purchased power.................................. 1,776,907 (1,699,482) (76,449) 976
Sales of purchased gas.................................... 434,202 (434,202) 7,455 7,455
Purchased power expense................................... 1,513,181 (1,436,732) (76,449) --
Purchased gas expense..................................... 457,418 (457,418) -- --
Cost of oil and natural gas burned by power plants........ 677,291 23,216 7,455 707,962
Six months ended June 30, 2001
Electricity and steam revenue............................. $ 1,100,870 $ 25,453 $ -- $ 1,126,323
Sales of purchased power.................................. 1,136,798 (1,021,713) (115,328) (243)
Sales of purchased gas.................................... 355,865 (355,865) 4,884 4,884
Purchased power expense................................... 1,111,588 (996,260) (115,328) --
Purchased gas expense..................................... 336,958 (336,958) -- --
Cost of oil and natural gas burned by power plants........ 516,439 (18,907) 4,884 502,416
Outlook
At August 9, 2002, we had 25 projects under construction, representing an
additional 11,650 megawatts of net capacity. The completion of our projects
currently under construction, which we expect to occur in the later half of
2004, would give us interests in 96 power plants totaling 28,539 megawatts.
Our new $2 billion revolving credit and term loan facilities and April 2002
issuance of 66 million shares of common stock together with our ongoing
financing programs and sales of non-strategic assets have helped to improve our
2002 liquidity position. For 2003 to 2004, our secured construction financing
revolving facilities will mature, requiring us to restructure or refinance this
indebtedness. We remain confident that we will have the ability to refinance
this indebtedness as it matures, but recognize that this is dependent, in part,
on market conditions that are difficult to predict and are outside of our
control. We have made significant progress in reducing our operations and
maintenance costs and general and administrative expenses per unit of electrical
generation as we have doubled our generation of electricity from the second
quarter of 2001 to the second quarter of 2002 and, as a result of the suspension
of certain of our development projects and the restructuring of our turbine
contracts completed to date, our capital expenditure requirements have been
reduced. We recognize that the pace of pricing and spark spread improvement is
dependent on the nation's economic recovery and on weather, particularly in the
summer and winter periods. We remain confident in our strategy, as outlined in
our Annual Report on Form 10-K for the year ended December 31, 2001, and
optimistic about our future performance. However, market conditions make it more
difficult to predict future results than in prior periods. Additional factors
that can affect our future performance are described in the "Risk Factors"
section of our Annual Report on Form 10-K for the year ended December 31, 2001.
Overview
Summary of Key Activities
Power Plant Development and Construction:
Date Project Description
-------- ------------------------------ --------------------------------
4/02 Island Cogeneration Commercial operation
4/02 Channel Energy Center Combined-cycle operation
5/02 Aries Power Peaker Plant Combined-cycle operation
5/02 Baytown Energy Center Commercial operation
6/02 Metcalf Energy Center Construction commenced
6/02 Decatur Energy Center Partial commercial operation
6/02 Freestone Energy Center Partial commercial operation
6/02 Zion Energy Center Commercial operation
6/02 Delta Energy Center Commercial operation
7/02 Freestone Energy Center Combined-cycle operation
7/02 Bethpage Energy Peaker Center Commercial operation
7/02 Yuba City Energy Center Commercial operation
8/02 Acadia Energy Center Commercial operation
-39-
Finance
Note Repayments and New Funding:
Date Amount Description
-------- ----------------------------- --------------------------------
5/10/02 $500.0 million Funding under two-year term loan
5/24/02 $100.0 million Funding for Gilroy and King City
Peaker Projects
5/31/02 $500.0 million Funding under two-year term loan
8/7/02 $50.0 million Repayment of peaker funding
Repurchases of Zero-Coupon Convertible Debentures Due 2021:
Date Amount
------- --------------
4/30/02 $685.5 million
Sale of Common Stock:
Date Offering Description Use of Proceeds
- --------- ------------------- ---------------------- ---------------------
4/30/02 $759 million, gross 66 million shares For general corporate
at $11.50 per share purposes, including
debt repayment
Other:
Date Description
- --------- -----------------------------------------------------------------
4/22/02 Renegotiation of California Department of Water Resources
long-term power contracts
6/28/02 Execution of definitive agreements with Wisconsin Public
Service for the sale of DePere Energy Center, including
termination of existing power purchase agreement
California Power Market
On April 22, 2002, we announced that we had renegotiated CES' long-term
power contracts with the California Department of Water Resources (the "DWR").
The Office of the Governor of California, the California Public Utilities
Commission (the "CPUC"), the California Electricity Oversight Board (the "EOB")
and the California Attorney General (the "AG") endorsed the renegotiated
contracts and agreed to drop all pending claims against us and our affiliates,
including withdrawing the complaint under Section 206 of the Federal Power Act
that had been filed by the CPUC and EOB with FERC, and the termination by the
CPUC and the EOB of their efforts to seek refunds from us and our affiliates
through FERC refund proceedings. In connection with the renegotiation, we have
agreed to pay $6 million over three years to the AG to resolve any and all
possible claims against us and our affiliates brought by the AG.
CES had signed three long-term contracts with DWR in February 2001,
comprising two 10-year baseload energy contracts and one 20-year peaking
contract. The renegotiation provided for the shortening of the duration of each
of the two 10-year, baseload energy contracts by two years and of the 20-year
peaker contract by ten years. These changes reduced DWR's long-term purchase
obligations. In addition, CES agreed to reduce the energy price on one baseload
contract from $61.00 to $59.60 per megawatt-hour, and to convert the energy
portion of the peaker contract to gas index pricing from fixed energy pricing.
CES also agreed to deliver up to 12.2 million megawatt-hours of additional
energy pursuant to the baseload energy contracts in 2002 and 2003. In connection
with the renegotiation, CES also agreed with DWR that DWR will have the right to
assume and complete four of our projects currently planned for California and in
the advanced development stage if we do not meet certain milestones with respect
to each project assumed, provided that DWR reimburses us for all construction
costs and certain other costs incurred by us to the date DWR assumes the
relevant project. The Company will generate over $8.7 billion in revenue between
2002 and 2011 from the DWR contracts.
In addition, the negotiation resolved the dispute with DWR concerning
payment of the capacity payment on the peaking contract. The contract provides
that through December 31, 2002, CES may earn a capacity payment by committing to
supply electricity to DWR from a source other than the peaker units designated
in the contract. DWR had made certain assertions challenging CES' right to
substitute units or provide replacement energy and had withheld capacity
payments in the amount of approximately $15.0 million since December 2001. As
part of the renegotiation, we have received payment in full on these withheld
capacity payments and will have the right to provide replacement capacity
through December 31, 2002, on the original contract terms. On May 2, 2002, each
of the CPUC and the EOB filed a Notice of Partial Withdrawal with Prejudice of
Complaint as to Calpine Energy Services, L.P. with the FERC.
-40-
Financial Market Risks
As an independent power producer 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. We enter into commodity financial instruments to convert floating
or indexed electricity and gas (and to a lesser extent oil and refined product)
prices to fixed prices in order to lessen our vulnerability to reductions in
electric prices for the electricity we generate, to reductions in gas prices for
the gas we produce, and to increases in gas prices for the fuel we consume in
our power plants. We seek to "self-hedge" our gas consumption exposure to an
extent with our own gas production position. Any hedging, balancing, or
optimization activities that we engage in are directly related to our
asset-based business model of owning and operating gas-fired electric power
plants and are designed to protect our "spark spread" (the difference between
our fuel cost and the revenue we receive for our electric generation). We hedge
exposures that arise from the ownership and operation of power plants and
related sales of electricity and purchases of natural gas, and we utilize
derivatives to optimize the returns we are able to achieve from these assets for
our shareholders. From time to time we have entered into contracts considered
energy trading contracts under EITF Issue No. 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities." However, our traders
have low capital at risk and value at risk limits for energy trading, and our
risk management policy limits, at any given time, our net sales of power to our
generation capacity and limits our net purchases of gas to our 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 and EITF Issue No.
98-10.
The change in fair value of outstanding commodity derivative instruments
from January 1, 2002, through June 30, 2002, is summarized in the table below
(in thousands):
Fair value of contracts outstanding at January 1, 2002........................................ $ (88,123)
(Gains) losses realized or otherwise settled during the period (1)......................... (95,167)
Changes in fair value attributable to changes in valuation techniques and assumptions...... --
Change in fair value attributable to new contracts and price movements..................... 176,748
Reclassification of Enron obligations from derivative assets and liabilities to
accounts payable (2)...................................................................... 221,117
---------
Fair value of contracts outstanding at June 30, 2002 (3)................................ $ 214,575
=========
- ----------
(1) Realized gains from commodity cash flow hedges of $86.8 million reported in
Note 8 of the financial statements and $8.4 million realized gain on
trading activity reported in the performance metrics section of the
management discussion and analysis, both included in this filing.
(2) At termination the Enron contracts ceased to be derivatives as defined by
SFAS 133; however, we are required to pay Enron for the contractual value
at termination. See Note 10 to the financial statements.
(3) Net assets reported in Note 8 of the Notes to Consolidated Financial
Statements included in this filing.
The fair value of outstanding derivative commodity instruments at June 30,
2002, based on price source and the period during which the instruments will
mature (i.e., be realized) are summarized in the table below (in thousands):
Fair Value Source 2002 2003-2004 2005-2006 After 2006 Total
- ----------------- ---------- --------- --------- ---------- ---------
Prices actively quoted................................ $ (22,541) $ 35,225 $ (9,143) $ -- $ 3,541
Prices provided by other external sources............. 81,796 88,434 35,119 24 205,373
Prices based on models and other valuation methods.... (2,273) (5,749) 16,334 (2,651) 5,661
---------- --------- --------- ---------- ---------
Total fair value................................... $ 56,982 $ 117,910 $ 42,310 $ (2,627) 214,575
========== ========= ========= ========== =========
-41-
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 function. Prices actively quoted
include validation with prices sourced from commodities exchanges (e.g., New
York Mercantile Exchange). Prices provided by other external sources include
quotes from commodity brokers and electronic trading platforms. Prices based on
models and other valuation methods are validated using quantitative methods.
The counterparty credit quality associated with the fair value of
outstanding derivative commodity instruments at June 30, 2002, and the period
during which the instruments will mature (i.e., be realized) are summarized in
the table below (in thousands):
Credit Quality (based on July 23, 2002, ratings) 2002 2003-2004 2005-2006 After 2006 Total
- ------------------------------------------------- ---------- --------- --------- ---------- ---------
Investment grade...................................... $ 10,457 $ 127,214 $ 51,990 $ (2,661) $ 187,000
Non-investment grade.................................. 48,945 (8,523) (9,680) 34 30,776
No external ratings................................... (2,420) (781) -- -- (3,201)
---------- --------- --------- ---------- ---------
Total fair value................................... $ 56,982 $ 117,910 $ 42,310 $ (2,627) $ 214,575
========== ========= ========= ========== =========
The fair value of outstanding derivative commodity instruments and the
change in fair value that would be expected from a ten percent adverse price
change are shown in the table below (in thousands):
Change in Fair
Value From
10% Adverse
Fair Value Price Change
---------- --------------
At June 30, 2002:
Crude oil............................. $ (2,315) $ 4,108
Electricity........................... 255,322 (43,196)
Natural gas........................... (38,432) (135,118)
---------- ----------
Total.............................. $ 214,575 $ (174,206)
========== ==========
Derivative commodity instruments included in the table are those included
in Note 8 to the unaudited 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
positive fair value of electricity derivative commodity instruments includes the
effect of decreased power prices versus our derivative forward commitments.
Conversely, the negative fair value of the natural gas derivatives reflects a
general decline in gas prices versus our derivative forward commitments.
Derivative commodity instruments offset physical positions exposed to the cash
market. 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 Calpine's
derivative portfolio would typically change by more than ten percent for earlier
forward months and less than ten percent for later forward months because of the
higher volatilities in the near term and the effects of discounting expected
future cash flows.
The primary factors affecting the fair value of our derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and MWh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions decreased 58%
from December 31, 2001, to June 30, 2002, while the total volume of open power
derivative positions decreased 10% for the same period. In that prices for
electricity and natural gas are among the most volatile of all commodity prices,
there may be material changes in the fair value of our derivatives over time,
driven both by price volatility and the changes in volume of open derivative
transactions. Under SFAS No. 133, the change since the last balance sheet date
in the total value of the derivatives (both assets and liabilities) is reflected
either in other comprehensive income ("OCI"), net of tax, or in the statement of
operations as an item (gain or loss) of current earnings. As of June 30, 2002,
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 six months ended June 30,
2002, have reflected this. See Note 8 for additional information on derivative
activity and also the 2001 Form 10-K for a further discussion of our accounting
policies related to derivative accounting. How we account for our derivatives
depends upon whether we have designated the derivative as a cash flow or fair
value hedge or not designated the derivative in a hedge relationship. The
following accounting applies:
-42-
o Changes in the value of derivatives designated as cash flow hedges,
net of any ineffectiveness, are recorded to OCI.
o Changes in the value of derivatives designated as fair value hedges
are recorded in the statement of operations with the offsetting change
in value of the hedge item also recorded in the statement of
operations. Any difference between these two entries to the statement
of operations represents hedge ineffectiveness.
o The change in value of derivatives not designated in hedge
relationships is recorded to the statement of operations.
In 2001 the FASB cleared SFAS No. 133 Implementation Issue No. C16
"Applying the Normal Purchases and Normal Sales Exception to Contracts That
Combine a Forward Contract and a Purchased Option Contract" ("C16"). The
guidance in C16 applies to fuel supply contracts that require delivery of a
contractual minimum quantity of fuel at a fixed price and have an option that
permits the holder to take specified additional amounts of fuel at the same
fixed price at various times. Under C16, the volumetric optionality provided by
such contracts is considered a purchased option that disqualifies the entire
derivative fuel supply contract from being eligible to qualify for the normal
purchases and normal sales exception in SFAS No. 133. On April 1, 2002, we
adopted C16. We have no fuel supply contracts to which C16 applies. However, one
of our equity method investees has fuel supply contracts subject to C16. The
equity investee also adopted C16 on April 1, 2002. Because the contracts
qualified as highly effective hedges of the equity method investee's forecasted
purchase of gas, the equity method investee designated the contracts as cash
flow hedges. Accordingly, we have recorded $7.8 million net of tax as a
cumulative effect of change in accounting principle to OCI for its share of the
equity method investee's OCI from accounting change.
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. In regards to foreign currency denominated
senior notes, the swap notional amounts equal the amount of the related
principal debt. The following tables summarize the fair market values of our
existing interest rate swap and currency swap agreements as of June 30, 2002,
(dollars in thousands):
Notional Principal Weighted Average Weighted Average Fair Market
Maturity Date Amount Interest Rate Interest Rate Value
------------- ------------------ ---------------- ---------------- -----------
(Pay) (Receive)
2011......... 51,760 6.9% 3-month US LIBOR $ (5,120)
2012......... 117,936 6.5% 3-month US LIBOR (10,943)
2014......... 67,929 6.7% 3-month US LIBOR (6,598)
---------- --- ---------
Total..... $ 237,625 6.7% 3-month US LIBOR $ (22,661)
========== === =========
Frequency of
Currency Fair Market
Maturity Date Notional Principal Fixed Currency Exchange Exchange Value
- ------------- ----------------------------------- ------------------------------- ------------- -----------
(Pay/Receive) (Pay/Receive)
2007......... US$127,763/C$200,000 US$5,545/C$8,750 Semi-annually $ 1,889
2008......... Pound sterling 109,550/Euro 175,000 Pound sterling 5,152/Euro 7,328 Semi-annually 1,868
---------
Total..... $ 3,757
=========
Long-term senior notes and construction/project financing -- Because of the
significant capital requirements within our industry, additional financing is
often needed to fund our growth. We use two primary forms of debt to raise this
financing -- long-term senior notes and related instruments including
Convertible Senior Notes Due 2006 and construction/project financing. Our senior
notes and related instruments bear fixed interest rates and are generally used
to fund acquisitions, replace construction financing for power plants once they
achieve commercial operations, and for general corporate purposes. Our
construction/project financing is funded through two separate credit agreements,
Calpine Construction Finance Company L.P. and Calpine Construction Finance
Company II, LLC. Borrowings under these credit agreements bear variable interest
rates, and are used exclusively to fund the construction of our power plants.
-43-
The following table summarizes the fair market value of our existing
long-term senior notes and construction/project financing as of June 30, 2002,
(dollars in thousands):
Outstanding Weighted Average Fair Market
Instrument Balance Interest Rate Value
- ----------------------------------------------------------------- ----------- ---------------- -----------
Long-term senior notes:
Senior Notes Due 2005......................................... $ 250,000 8.3% $ 145,000
Senior Notes Due 2006......................................... 171,750 10.5% 108,203
Senior Notes Due 2006......................................... 250,000 7.6% 140,000
Convertible Senior Notes Due 2006............................. 1,200,000 4.0% 924,000
Senior Notes Due 2007......................................... 275,000 8.8% 154,000
Senior Notes Due 2007......................................... 131,700 8.8% 84,288
Senior Notes Due 2008......................................... 400,000 7.9% 208,000
Senior Notes Due 2008......................................... 2,030,000 8.5% 1,096,200
Senior Notes Due 2008......................................... 172,516 8.4% 115,586
Senior Notes Due 2009......................................... 350,000 7.8% 182,000
Senior Notes Due 2010......................................... 750,000 8.6% 397,500
Senior Notes Due 2011......................................... 2,000,000 8.5% 1,060,000
Senior Notes Due 2011......................................... 304,920 8.9% 198,198
----------- ----- -----------
Total long-term senior notes............................... $ 8,285,886 7.8% $ 4,812,975
=========== ===== ===========
Construction/project financing:
Peaker financing (1).......................................... $ 100,000 4.4% (2) $ 100,000
Term loan due (due 2004)...................................... 1,000,000 3-month US LIBOR 1,000,000
Calpine Construction Finance Company L.P. (due 2003).......... 981,400 1-month US LIBOR 981,400
Calpine Construction Finance Company II, LLC (due 2004)....... 2,452,697 1-month US LIBOR 2,452,697
----------- -----------
Total long-term construction/project financing............. $ 4,534,097 $ 4,534,097
=========== ===========
(1) $50 million repaid August 2002, $50 million due September 30,2002.
(2) Blended rate of two tranches.
Short-term investments -- As of June 30, 2002, we had short-term
investments of $190.0 million. These short-term investments consist of highly
liquid investments with original maturities of less than three months. We have
the ability to hold these investments to maturity, and as a result, we would not
expect the value of these investments to be affected to any significant degree
by the effect of a sudden change in market interest rates.
Construction/project financing facilities -- In 2003 and 2004, $981.4
million and $2,452.7 million, respectively, under our secured construction
financing revolving facilities will mature, requiring us to refinance this
indebtedness. We remain confident that we will have the ability to refinance
this indebtedness as it matures, but recognize that this is dependent, in part,
on market conditions that are difficult to predict.
New Accounting Pronouncements
In June 2001 we adopted SFAS No. 141, "Business Combinations," which
supersedes Accounting Principles Board ("APB") Opinion No. 16, "Business
Combinations" and SFAS No. 38, "Accounting for Preacquisition Contingencies of
Purchased Enterprises." SFAS No. 141 eliminated the pooling-of-interests method
of accounting for business combinations and modified the recognition of
intangible assets and disclosure requirements. Adoption of SFAS No. 141 did not
have a material effect on the consolidated financial statements.
In June 2001 the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets," which supersedes APB Opinion No. 17, "Intangible Assets." SFAS No. 142
eliminates the current requirement to amortize goodwill and indefinite-lived
intangible assets, extends the allowable useful lives of certain intangible
assets, and requires impairment testing and recognition for goodwill and
intangible assets. SFAS No. 142 will apply to goodwill and other intangible
assets arising from transactions completed both before and after its effective
date. The provisions of SFAS No. 142 are required to be applied starting with
fiscal years beginning after December 15, 2001. See Note 4 for more information.
In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which amends SFAS No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies." SFAS No. 143 addresses financial accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. SFAS No. 143
requires that the fair value of a liability for an asset retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of
-44-
fair value can be made. SFAS No. 143 is effective for financial statements
issued for fiscal years beginning after June 15, 2002. We do not believe that
SFAS No. 143 will have a material impact on our consolidated financial
statements.
On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets," which supersedes SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," and the accounting and reporting provisions of APB Opinion No. 30,
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," for the disposal of a segment of a business (as
previously defined in that APB Opinion). SFAS No. 144 establishes a single
accounting model, based on the framework established in SFAS No. 121, for
long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several
significant implementation issues related to SFAS No. 121, such as eliminating
the requirement to allocate goodwill to long-lived assets to be tested for
impairment and establishing criteria to define whether a long-lived asset is
held for sale. Adoption of SFAS No. 144 has not had a material effect on the
consolidated financial statements.
In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" stating that
gains or losses from extinguishment of debt that fall outside the scope of APB
Opinion No. 30 should not be classified as extraordinary. SFAS No. 145 also
amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency
between the required accounting for sale-leaseback transactions and the required
accounting for certain lease modifications that have economic effects that are
similar to sale-leaseback transactions. SFAS No. 145 also amends other existing
authoritative pronouncements to make various technical corrections, clarify
meanings, or describe their applicability under changed conditions. The
provisions related to the rescission of SFAS No. 4 shall be applied in fiscal
years beginning after May 15, 2002. The provisions related to SFAS No. 13 shall
be effective for transactions occurring after May 15, 2002. All other provisions
shall be effective for financial statements issued on or after May 15, 2002,
with early adoption encouraged. We have not completed our analysis but believe
that SFAS No. 145 may have a material effect on the presentation of our
financial statements, but no impact on net income.
In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (Including Certain
Costs Incurred in a Restructuring)." We will adopt the provisions of SFAS No.
146 for restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under Issue No. 94-3, a
liability for an exit cost was recognized at the date of commitment to an exit
plan. SFAS No. 146 also establishes that the liability should initially be
measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the
timing of recognizing future restructuring costs as well as the amounts
recognized. We do not believe that SFAS No. 146 will have a material effect on
our consolidated financial statements.
In June 2002 the EITF reached a consensus on two of the three issues
considered in EITF 02-03, "Recognition and Reporting of Gains and Losses on
Energy Trading Contracts under EITF Issues No. 98-10, `Accounting for Contracts
Involved in Energy Trading and Risk Management Activities' and No. 00-17,
`Measuring the Fair Value of Energy-Related Contracts in applying Issue No.
98-10.'" The issues upon which the EITF reached a consensus required net
presentation, both prospective and retroactive, of energy trading contracts in a
company's financial statements and required that companies make certain
disclosures regarding their energy trading contracts. The net presentation
requirement is effective for financial statements issued for periods ending
after July 15, 2002, and the disclosure requirements are effective for financial
statements issued for fiscal years ending after July 15, 2002. We are still
assessing the impacts of adopting this standard on our financial statements, but
we believe, as a minimum, all energy trading contracts will be reported net,
rather than gross, upon adoption of this standard. The standard is expected to
have a material impact on total revenues and expenses, but no impact on net
income.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in Item 2.
-45-
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
Securities Derivative Lawsuit. On December 17, 2001, a shareholder filed a
derivative lawsuit on behalf of Calpine against our directors and one of our
senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. (No.
CV803872), and is pending in the California Superior Court, Santa Clara County.
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. We have filed a demurrer
asking the court to dismiss the complaint on the ground that the shareholder
plaintiff lacks standing to pursue claims on behalf of Calpine. The individual
defendants have filed a demurrer asking the court to dismiss the complaint on
the ground that it fails to state any claims against them. We consider this
lawsuit to be without merit and intend to vigorously defend against it.
Securities Class Action Lawsuits. Fourteen shareholder lawsuits have been
filed against Calpine and certain of its officers in the United States District
Court, 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 were 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 our securities between January 5, 2001, and December
13, 2001.
The complaints in these fourteen actions allege that, during the purported
class periods, certain senior Calpine executives issued false and misleading
statements about our 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. We expect that these actions, as well as any related actions that may be
filed in the future, will be consolidated by the court into a single securities
class action.
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 to those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of our 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 Prospectus
Supplement dated October 11, 2001, for the 2011 Notes contained false and
misleading statements regarding our financial condition. This action names
Calpine, certain of our 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. We expect that this action will either be
consolidated with the above-referenced actions or will proceed as a parallel
related action before the same judge presiding over the other actions. We
consider the allegations against Calpine in each of these lawsuits to be without
merit, and we intend to defend vigorously against them.
California Business & Professions Code Section 17200 Cases--The lead case,
T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al., was
served on May 2, 2002, by T&E Pastorino Nursery, on behalf of itself and all
others similarly situated. This purported class action complaint 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 five other similar complaints for violations of
Section 17200 captioned Bronco Don Holdings, LLP. v. Duke Energy Marketing and
Trading, et al.; Century Theatres, Inc. v. Allegheny Energy Supply Company, LLC;
RDJ Farms, Inc. v. Allegheny Energy Supply Company, LLC; J&M Karsant Family
Limited Partnership v. Duke Energy Trading and Marketing, LLC; and Leo's Day and
Night Pharmacy v. Duke Energy Trading and Marketing, LLC. All six of these cases
have been removed in a multidistrict litigation proceeding from the various
state courts in which they were originally filed to federal court, where a
motion is now pending to transfer and consolidate these cases for pretrial
proceedings with other cases in which we are not named as a defendant. In
addition, plaintiffs in the T&E Pastorino Nursery case have filed a motion to
remand that matter to California state court.
We consider the allegations against Calpine in each of these lawsuits to be
without merit, and we intend to vigorously defend against them.
-46-
California Department of Water Resources Case. On May 1, 2002, California
State Senator Tom McClintock and others filed a complaint against Vikram
Budhraja, a consultant to DWR, DWR itself, and more than twenty-nine energy
providers and other interested parties, including Calpine. The complaint alleges
that the long-term power contracts that DWR entered into with these energy
providers, including Calpine, are rendered void because Budhraja, who negotiated
the contracts on behalf of DWR, allegedly had an undisclosed financial interest
in the contracts due to his connection to one of the energy providers, Edison
International. Among other things, the complaint seeks an injunction prohibiting
further performance of the long-term contracts and restitution of any funds paid
to energy providers by the State of California under the contracts. We consider
the allegations against Calpine in this lawsuit to be without merit and intend
to vigorously defend against them.
Nevada Section 206 Complaint. On December 4, 2001, NPC and SPPC filed a
complaint with the Federal Energy Regulatory Commission ("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. We consider the complaint to be without merit and are vigorously
defending against it.
Emissions Credits Lawsuit. As described in our previous reports, on March
5, 2002, we sued Automated Credit Exchange ("ACE") in the Superior Court of the
State of California for the County of Alameda for negligence and breach of
contract to recover reclaim trading credits, a form of emission reduction
credits that should have been held in our account with U.S. Trust Company ("US
Trust"). Calpine and ACE entered into a settlement agreement on March 29, 2002,
pursuant to which ACE made a payment to us of $7 million and transferred to us
the rights to the emission reduction credits to be held by ACE, and we dismissed
our complaint against ACE. We recognized the $7 million 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 our 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. InterGen's complaint refers to the payment
by ACE of $7 million to us, alleging that InterGen's ability to recover from
EonXchange has been undermined thereby. We are unable to assess the likelihood
of InterGen's complaint being upheld at this time.
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 4. Submission of Matters to a Vote of Security Holders.
Our Annual Meeting of Stockholders was held on May 23, 2002, (the "Annual
Meeting") in Aptos, California. At the Annual Meeting, the stockholders voted on
the following matters: (i) the proposal to elect two Class III Directors to the
Board of Directors for a term of three years expiring in 2005, (ii) the proposal
to amend the Company's 1996 Stock Incentive Plan to increase by 12 million the
number of shares of the Company's Common Stock, par value $.001 per share
("Common Stock") available for grants of options and other stock-based awards
under such plan, (iii) the proposal to amend the Company's 2000 Employee Stock
Purchase Plan to increase by 8 million the number of Common Stock available for
grants of purchase rights under such plan, (iv) two stockholder proposals
regarding (a) the composition of the Company's Board of Directors and (b) the
Company's stockholder rights plan, (v) the proposal to ratify the appointment of
Deloitte & Touche LLP as independent accountants for the Company for the fiscal
year ending December 31, 2002. The stockholders elected management's nominees as
the Class III Directors in an uncontested election, approved the amendment to
the Company's 1996 Stock Incentive Plan to increase by 12 million the number of
shares of the Company's Common Stock available for grants of options and other
stock-based awards under such plan, approved the amendment to the Company's 2000
Employee Stock Purchase Plan to increase by 8 million the number of Common Stock
available for grants of purchase rights under such plan, rejected the
stockholder proposal regarding the composition of the Company's Board of
Directors, approved the stockholder proposal that the Board of Directors be
requested to redeem the stockholders right plan unless such plan is approved by
a majority vote of the stockholders to be held as soon as may be practicable,
and ratified the appointment of independent accountants by the following votes,
respectively:
-47-
(i) Election of Peter Cartwright as Class III Director for a three-year term
expiring 2005: 266,247,019 FOR and 3,748,417 ABSTAIN;
Election of Susan C. Schwab as Class III Director for a three-year term
expiring 2005: 266,315,844 FOR and 3,679,592 ABSTAIN;
(ii) Amendment to the Company's 1996 Stock Incentive Plan to increase by 12
million the number of shares of the Company's Common Stock available for
grants of options and other stock-based awards under such plan:
84,312,894 FOR, 68,320,701 AGAINST, 2,204,515 ABSTAIN, and 115,157,326
Broker non-votes;
(iii) Amendment to the Company's Employee Stock Purchase Plan to increase by 8
million the number of shares of the Company's Common Stock available for
grants of purchase rights under such plan: 137,879,225 FOR, 14,783,654
AGAINST, 2,175,231 ABSTAIN, and 115,157,326 Broker non-votes;
(iv) Proposal regarding composition of the Company's Board of Directors:
51,697,103 FOR, 100,003,353 AGAINST, 3,137,654 ABSTAIN, and 115,157,326
Broker non-votes;
(v) Proposal that the Board of Directors be requested to redeem the
stockholders right plan unless such plan is approved by a majority vote
of the stockholders to be held as soon as may be practicable: 92,639,512
FOR, 58,655,073 AGAINST, 3,543,525 ABSTAIN, and 115,157,326 Broker
non-votes;
(vi) Ratification of the appointment of Deloitte & Touche LLP as
independent accountants for the fiscal year ending December 31, 2002:
261,041,303 FOR, 4,899,355 AGAINST, and 4,054,779 ABSTAIN.
The three-year terms of Class I and Class II Directors continued after
the Annual Meeting and will expire in 2003 and 2004, respectively. The Class I
Directors are Jeffrey E. Garten, George J. Stathakis, and John O. Wilson. The
Class II Directors are Ann B. Curtis, Kenneth T. Derr and Gerald Greenwald.
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)
*10.1 Second Amended and Restated Credit Agreement ("Second Amended and
Restated Credit Agreement") dated as of May 23, 2000, among the
Company, Bayerische Landesbank, as Co-Arranger and Syndication
Agent, The Bank of Nova Scotia, as Lead Arranger and
Administrative Agent, and the Lenders named therein (g)
-48-
EXHIBIT INDEX
(continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------------------------------------------------------------
*10.2 First Amendment and Waiver to Second Amended and Restated Credit
Agreement, dated as of April 19, 2001, among the Company, The
Bank of Nova Scotia, as Administrative Agent, and the Lenders
named therein (f)
*10.3 Second Amendment to Second Amended and Restated Credit Agreement,
dated as of March 8, 2002, among the Company, The Bank of Nova
Scotia, as Administrative Agent, and the Lenders named therein
(f)
*10.4 Third Amendment to Second Amended and Restated Credit Agreement,
dated as of May 9, 2002, among the Company, The Bank of Nova
Scotia, as Administrative Agent, and the Lenders named therein
(e)
*10.5 Credit Agreement, dated as of March 8, 2002, among the Company,
the Lenders named therein, The Bank of Nova Scotia and Bayerische
Landesbank Girozentrale, as lead arrangers and bookrunners,
Salomon Smith Barney Inc. and Deutsche Banc Alex. Brown Inc., as
lead arrangers and bookrunners, Bank of America, National
Association, and Credit Suisse First Boston, Cayman Islands
Branch, as lead arrangers and syndication agents, TD Securities
(USA) Inc., as lead arranger, The Bank of Nova Scotia, as joint
administrative agent and funding agent, and Citicorp USA, Inc.,
as joint administrative agent (f)
*10.6 First Amendment to Credit Agreement, dated as of May 9, 2002,
among the Company, The Bank of Nova Scotia, as Joint
Administrative Agent and Funding Agent, Citicorp USA, Inc., as
Joint Administrative Agent, and the Lenders named therein (e)
+10.7 Increase in Term B Loan Commitment Amount Notice, effective as of
May 31, 2002, by The Bank of Nova Scotia and Citicorp USA, Inc.,
as Administrative Agents
*10.8 Assignment and Security Agreement, dated as of March 8, 2002, by
the Company in favor of The Bank of Nova Scotia, as
administrative agent for each of the Lender Parties named therein
(f)
*10.9 Pledge Agreement, dated as of March 8, 2002, by the Company in
favor of The Bank of Nova Scotia, as Agent for the Lender Parties
named therein (f)
*10.10 Amendment Number One to Pledge Agreement, dated as of May 9,
2002, among the Company and The Bank of Nova Scotia, as Joint
Administrative Agent and Funding Agent (e)
*10.11 Pledge Agreement, dated as of March 8, 2002, by Quintana Minerals
(USA), Inc., JOQ Canada, Inc. and Quintana Canada Holdings, LLC
in favor of The Bank of Nova Scotia, as Agent for the Lender
Parties named therein (f)
*10.12 First Amendment Pledge Agreement, dated as of May 9, 2002, by the
Company in favor of The Bank of Nova Scotia, as Agent for each of
the Lender Parties named therein (e)
*10.13 First Amendment Pledge Agreement (Membership Interests), dated as
of May 9, 2002, by the Company in favor of The Bank of Nova
Scotia, as Agent for each of the Lender Parties named therein (e)
*10.14 Note Pledge Agreement, dated as of May 9, 2002, by the Company in
favor of The Bank of Nova Scotia, as Agent for each of the Lender
Parties named therein (e)
+10.15 Hazardous Materials Undertaking and Indemnity (Multistate), dated
as of May 9, 2002, by the Company in favor of The Bank of Nova
Scotia, as Agent
+10.16 Hazardous Materials Undertaking and Indemnity (California), dated
as of May 9, 2002, by the Company in favor of The Bank of Nova
Scotia, as Agent
+10.17 Form of Mortgage, Deed of Trust, Assignment, Security Agreement,
Financing Statement and Fixture Filing (Multistate), from the
Company to Jon Burckin and Kemp Leonard, as Trustees, and The
Bank of Nova Scotia, as Agent
-49-
EXHIBIT INDEX
(continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------------------------------------------------------------
+10.18 Form of Deed of Trust with Power of Sale, Assignment of
Production, Security Agreement, Financing Statement and Fixture
Filing (California), dated as of May 1, 2002, from the Company to
Chicago Title Insurance Company, as Trustee, and The Bank of Nova
Scotia, as Agent
+10.19 Form of Mortgage, Deed of Trust, Assignment, Security Agreement,
Financing Statement and Fixture Filing (Colorado), dated as of
May 1, 2002, from the Company to Kemp Leonard and John Quick, as
Trustees, and The Bank of Nova Scotia, as Agent
+10.20 Form of Mortgage, Assignment, Security Agreement and Financing
Statement (Louisiana), dated as of May 1, 2002, from the Company
to The Bank of Nova Scotia, as Agent
+10.21 Form of Mortgage, Deed of Trust, Assignment, Security Agreement,
Financing Statement and Fixture Filing (New Mexico), dated as of
May 1, 2002, from the Company to Kemp Leonard and John Quick, as
Trustees, and The Bank of Nova Scotia, as Agent
+99.1 Certification of Peter Cartwright Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
+99.2 Certification of Robert D. Kelly 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 Current Report on Form
8-K dated July 25, 2000, filed with the SEC on August 9, 2000.
(b)Reports on Form 8-K
The registrant filed the following reports on Form 8-K or Form 8-K/A during
the quarter ended June 30, 2002:
. Date of Report Date Filed Item Reported
--------------------------- ---------------- -------------
March 25, 2002.............. April 8, 2002 4,7
April 22, 2002.............. April 25, 2002 5,7
April 24, 2002.............. April 26, 2002 5,7
May 2, 2002................. May 3, 2002 5,7
May 31, 2002................ June 4, 2002 5,7
June 4, 2002................ June 6, 2002 5,7
-50-
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
Date: August 9, 2002 By: /s/ ROBERT D. KELLY
-------------------------------------
Robert D. Kelly
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 9, 2002 By: /s/ CHARLES B. CLARK, JR.
--------------------------------------
Charles B. Clark, Jr.
Senior Vice President and
Corporate Controller
(Principal Accounting Officer)
-51-
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)
*10.1 Second Amended and Restated Credit Agreement ("Second Amended and
Restated Credit Agreement") dated as of May 23, 2000, among the
Company, Bayerische Landesbank, as Co-Arranger and Syndication
Agent, The Bank of Nova Scotia, as Lead Arranger and
Administrative Agent, and the Lenders named therein (g)
*10.2 First Amendment and Waiver to Second Amended and Restated Credit
Agreement, dated as of April 19, 2001, among the Company, The
Bank of Nova Scotia, as Administrative Agent, and the Lenders
named therein (f)
*10.3 Second Amendment to Second Amended and Restated Credit Agreement,
dated as of March 8, 2002, among the Company, The Bank of Nova
Scotia, as Administrative Agent, and the Lenders named therein
(f)
*10.4 Third Amendment to Second Amended and Restated Credit Agreement,
dated as of May 9, 2002, among the Company, The Bank of Nova
Scotia, as Administrative Agent, and the Lenders named therein
(e)
*10.5 Credit Agreement, dated as of March 8, 2002, among the Company,
the Lenders named therein, The Bank of Nova Scotia and Bayerische
Landesbank Girozentrale, as lead arrangers and bookrunners,
Salomon Smith Barney Inc. and Deutsche Banc Alex. Brown Inc., as
lead arrangers and bookrunners, Bank of America, National
Association, and Credit Suisse First Boston, Cayman Islands
Branch, as lead arrangers and syndication agents, TD Securities
(USA) Inc., as lead arranger, The Bank of Nova Scotia, as joint
administrative agent and funding agent, and Citicorp USA, Inc.,
as joint administrative agent (f)
*10.6 First Amendment to Credit Agreement, dated as of May 9, 2002,
among the Company, The Bank of Nova Scotia, as Joint
Administrative Agent and Funding Agent, Citicorp USA, Inc., as
Joint Administrative Agent, and the Lenders named therein (e)
+10.7 Increase in Term B Loan Commitment Amount Notice, effective as of
May 31, 2002, by The Bank of Nova Scotia and Citicorp USA, Inc.,
as Administrative Agents
*10.8 Assignment and Security Agreement, dated as of March 8, 2002, by
the Company in favor of The Bank of Nova Scotia, as
administrative agent for each of the Lender Parties named therein
(f)
*10.9 Pledge Agreement, dated as of March 8, 2002, by the Company in
favor of The Bank of Nova Scotia, as Agent for the Lender Parties
named therein (f)
-52-
EXHIBIT INDEX
(continued)
EXHIBIT
NUMBER DESCRIPTION
------- -----------------------------------------------------------------
*10.10 Amendment Number One to Pledge Agreement, dated as of May 9,
2002, among the Company and The Bank of Nova Scotia, as Joint
Administrative Agent and Funding Agent (e)
*10.11 Pledge Agreement, dated as of March 8, 2002, by Quintana Minerals
(USA), Inc., JOQ Canada, Inc. and Quintana Canada Holdings, LLC
in favor of The Bank of Nova Scotia, as Agent for the Lender
Parties named therein (f)
*10.12 First Amendment Pledge Agreement, dated as of May 9, 2002, by the
Company in favor of The Bank of Nova Scotia, as Agent for each of
the Lender Parties named therein (e)
*10.13 First Amendment Pledge Agreement (Membership Interests), dated as
of May 9, 2002, by the Company in favor of The Bank of Nova
Scotia, as Agent for each of the Lender Parties named therein (e)
*10.14 Note Pledge Agreement, dated as of May 9, 2002, by the Company in
favor of The Bank of Nova Scotia, as Agent for each of the Lender
Parties named therein (e)
+10.15 Hazardous Materials Undertaking and Indemnity (Multistate), dated
as of May 9, 2002, by the Company in favor of The Bank of Nova
Scotia, as Agent
+10.16 Hazardous Materials Undertaking and Indemnity (California), dated
as of May 9, 2002, by the Company in favor of The Bank of Nova
Scotia, as Agent
+10.17 Form of Mortgage, Deed of Trust, Assignment, Security Agreement,
Financing Statement and Fixture Filing (Multistate), from the
Company to Jon Burckin and Kemp Leonard, as Trustees, and The
Bank of Nova Scotia, as Agent
+10.18 Form of Deed of Trust with Power of Sale, Assignment of
Production, Security Agreement, Financing Statement and Fixture
Filing (California), dated as of May 1, 2002, from the Company to
Chicago Title Insurance Company, as Trustee, and The Bank of Nova
Scotia, as Agent
+10.19 Form of Mortgage, Deed of Trust, Assignment, Security Agreement,
Financing Statement and Fixture Filing (Colorado), dated as of
May 1, 2002, from the Company to Kemp Leonard and John Quick, as
Trustees, and The Bank of Nova Scotia, as Agent
+10.20 Form of Mortgage, Assignment, Security Agreement and Financing
Statement (Louisiana), dated as of May 1, 2002, from the Company
to The Bank of Nova Scotia, as Agent
+10.21 Form of Mortgage, Deed of Trust, Assignment, Security Agreement,
Financing Statement and Fixture Filing (New Mexico), dated as of
May 1, 2002, from the Company to Kemp Leonard and John Quick, as
Trustees, and The Bank of Nova Scotia, as Agent
+99.1 Certification of Peter Cartwright Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
+99.2 Certification of Robert D. Kelly Pursuant to 18 U.S.C. Section
1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
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* 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.
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(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 Current Report on Form
8-K dated July 25, 2000, filed with the SEC on August 9, 2000.
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