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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 September 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:
377,999,176 shares of Common Stock, par value $.001 per share, outstanding on
November 12, 2002
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CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Quarter Ended September 30, 2002
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Condensed Balance Sheets September 30, 2002 and December 31, 2001....................... 3
Consolidated Condensed Statements of Operations For the Three and Nine Months
Ended September 30, 2002 and 2001.................................................................. 5
Consolidated Condensed Statements of Cash Flows For the Nine Months
Ended September 30, 2002 and 2001.................................................................. 7
Notes to Consolidated Condensed Financial Statements September 30, 2002.............................. 8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................... 29
Item 3. Quantitative and Qualitative Disclosures About Market Risk.............................................. 50
Item 4. Controls and Procedures................................................................................. 50
PART II - OTHER INFORMATION
Item 1. Legal Proceedings....................................................................................... 50
Item 6. Exhibits and Reports on Form 8-K........................................................................ 52
Signatures........................................................................................................... 54
Certifications....................................................................................................... 55
-2-
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Balance Sheets
September 30, 2002 and December 31, 2001
(In thousands, except share amounts)
September 30, December 31,
2002 2001
-------------- ------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents ..................................................................... $ 659,694 $ 1,525,417
Accounts receivable, net ...................................................................... 838,632 956,596
Margin deposits and other prepaid expense ..................................................... 200,036 480,656
Inventories ................................................................................... 104,813 78,862
Current derivative assets ..................................................................... 556,259 763,162
Current assets held for sale .................................................................. 19,920 9,484
Other current assets .......................................................................... 297,742 193,525
------------ ------------
Total current assets ....................................................................... 2,677,096 4,007,702
------------ ------------
Restricted cash .................................................................................. 101,291 95,833
Notes receivable, net of current portion ......................................................... 193,767 158,124
Project development costs ........................................................................ 156,743 176,296
Investments in power projects .................................................................... 428,610 390,609
Deferred financing costs ......................................................................... 213,636 210,811
Property, plant and equipment, net ............................................................... 17,483,400 14,971,080
Goodwill and other intangible assets, net ........................................................ 128,281 141,120
Long-term derivative assets ...................................................................... 548,510 564,952
Long-term assets held for sale ................................................................... 241,474 308,463
Other assets ..................................................................................... 516,518 304,562
------------ ------------
Total assets ............................................................................. $ 22,689,326 $ 21,329,552
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable .............................................................................. $ 1,117,801 $ 1,283,843
Accrued payroll and related expense ........................................................... 46,352 57,285
Accrued interest payable ...................................................................... 202,947 160,115
Notes payable and borrowings under lines of credit, current portion ........................... 250,389 23,238
Capital lease obligation, current portion ..................................................... 3,001 2,206
Construction/project financing, current portion ............................................... 167,509 --
Zero-Coupon Convertible Debentures Due 2021 ................................................... -- 878,000
Current derivative liabilities ................................................................ 449,521 625,339
Current liabilities held for sale ............................................................. 4,522 4,576
Other current liabilities ..................................................................... 193,117 194,236
------------ ------------
Total current liabilities .................................................................. 2,435,159 3,228,838
------------ ------------
Term loan ........................................................................................ 1,000,000 --
Notes payable and borrowings under lines of credit, net of current portion ....................... 2,453 74,750
Capital lease obligation, net of current portion ................................................. 205,149 207,219
Construction/project financing, net of current portion ........................................... 3,510,595 3,393,410
Convertible Senior Notes Due 2006 ................................................................ 1,200,000 1,100,000
Senior notes ..................................................................................... 7,089,746 7,049,038
Deferred income taxes, net ....................................................................... 1,036,539 958,399
Deferred lease incentive ......................................................................... 54,608 57,236
Deferred revenue ................................................................................. 243,214 154,381
Long-term derivative liabilities ................................................................. 549,569 822,848
Long-term liabilities held for sale .............................................................. 5,983 5,947
Other liabilities ................................................................................ 112,409 96,504
------------ ------------
Total liabilities ........................................................................ 17,445,424 17,148,570
------------ ------------
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts ... 1,123,787 1,123,024
Minority interests ............................................................................... 198,875 47,389
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(continues next page)
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CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Balance Sheets
September 30, 2002 and December 31, 2001
(In thousands, except share amounts)
(continued)
September 30, December 31,
2002 2001
-------------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
(continued)
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 377,830,124 shares in 2002 and 307,058,751 shares in 2001 ............. 378 307
Additional paid-in capital ....................................................................... 2,795,582 2,040,836
Retained earnings ................................................................................ 1,355,597 1,196,000
Accumulated other comprehensive (loss) ........................................................... (230,317) (226,574)
------------ ------------
Total stockholders' equity .................................................................... 3,921,240 3,010,569
------------ ------------
Total liabilities and stockholders' equity ................................................. $ 22,689,326 $ 21,329,552
============ ============
The accompanying notes are an integral part of these consolidated
condensed financial statements.
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CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Operations
For the Three and Nine Months Ended September 30, 2002 and 2001
(In thousands, except per share amounts)
(unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- ------------
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue ................................ $ 947,326 $ 710,506 $ 2,269,892 $ 1,804,889
Sales of purchased power for hedging and optimization ........ 1,282,976 1,653,088 2,526,555 2,680,488
----------- ----------- ----------- -----------
Total electric generation and marketing revenue ............ 2,230,302 2,363,594 4,796,447 4,485,377
Oil and gas production and marketing revenue
Oil and gas sales ............................................ 21,827 54,693 89,585 239,940
Sales of purchased gas for hedging and optimization .......... 231,893 56,916 666,095 412,782
----------- ----------- ----------- -----------
Total oil and gas production and marketing revenue ......... 253,720 111,609 755,680 652,722
Trading revenue, net
Realized revenue on power and gas trading transactions,
net ......................................................... 6,845 16,700 15,276 21,340
Unrealized mark-to-market gain (loss) on power and gas
transactions, net ........................................... (10,957) 7,128 (5,952) 107,862
----------- ----------- ----------- -----------
Total trading revenue, net ................................. (4,112) 23,828 9,324 129,202
Income from unconsolidated investments in power projects ........ 10,176 6,859 10,499 9,021
Other revenue ................................................... 4,924 14,261 14,792 28,444
----------- ----------- ----------- -----------
Total revenue ........................................... 2,495,010 2,520,151 5,586,742 5,304,766
----------- ----------- ----------- -----------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense ...................................... 141,262 93,709 374,497 246,045
Royalty expense .............................................. 4,743 5,255 13,092 23,181
Purchased power expense for hedging and optimization ......... 1,059,840 1,394,871 2,039,954 2,396,804
----------- ----------- ----------- -----------
Total electric generation and marketing expense ............ 1,205,845 1,493,835 2,427,543 2,666,030
Oil and gas production and marketing expense
Oil and gas production expense ............................... 22,953 13,009 67,381 62,371
Purchased gas expense for hedging and optimization ........... 220,775 52,856 678,192 389,814
----------- ----------- ----------- -----------
Total oil and gas production and marketing expense ......... 243,728 65,865 745,573 452,185
Fuel expense .................................................... 525,478 327,947 1,208,092 846,195
Depreciation, depletion and amortization expense ................ 117,568 80,044 310,943 199,509
Operating lease expense ......................................... 36,520 27,830 108,917 83,289
Other expense ................................................... 3,539 3,485 8,333 9,474
----------- ----------- ----------- -----------
Total cost of revenue ................................... 2,132,678 1,999,006 4,809,401 4,256,682
----------- ----------- ----------- -----------
Gross profit ......................................... 362,332 521,145 777,341 1,048,084
Project development expense ........................................ 23,922 4,894 59,973 25,106
Equipment cancellation charge ...................................... 3,714 -- 172,185 --
General and administrative expense ................................. 57,280 29,357 170,369 114,924
Merger expense ..................................................... -- -- -- 41,627
----------- ----------- ----------- -----------
Income from operations .......................................... 277,416 486,894 374,814 866,427
Interest expense ................................................... 113,847 47,657 239,112 107,473
Distributions on trust preferred securities ........................ 15,386 15,385 46,159 45,948
Interest income .................................................... (10,842) (21,073) (32,780) (60,870)
Other (income)/expense ............................................. (33,778) (7,875) (49,128) (15,092)
----------- ----------- ----------- -----------
Income before provision for income taxes ........................ 192,803 452,800 171,451 788,968
Provision for income taxes ......................................... 48,406 139,304 38,805 278,161
----------- ----------- ----------- -----------
Income before discontinued operations and cumulative effect
of a change in accounting principle ............................ 144,397 313,496 132,646 510,807
Discontinued operations, net of tax
provision of $9,675, $4,903, $15,059 and $24,374 .................. 16,950 7,303 26,950 36,284
Cumulative effect of a change in accounting principle, net of
tax provision of $--, $--, $--and $669 ............................ -- -- -- 1,036
----------- ----------- ----------- -----------
Net income ........................................... $ 161,347 $ 320,799 $ 159,596 $ 548,127
=========== =========== =========== ===========
(continues next page)
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CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Operations
For the Three and Nine Months Ended September 30, 2002 and 2001
(In thousands, except per share amounts)
(unaudited)
(continued)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- ------------
Basic earnings per common share:
Weighted average shares of common stock outstanding ............. 376,957 304,666 346,816 302,649
Income before discontinued operations and cumulative effect
of a change in accounting principle ............................ $ 0.38 $ 1.03 $ 0.38 $ 1.69
Income from discontinued operations, net of tax ................. $ 0.05 $ 0.02 $ 0.08 $ 0.12
Cumulative effect of a change in accounting principle ........... $ -- $ -- $ -- $ --
----------- ----------- ----------- -----------
Net income ........................................... $ 0.43 $ 1.05 $ 0.46 $ 1.81
=========== =========== =========== ===========
Diluted earnings per common share:
Weighted average shares of common stock outstanding before
dilutive effect of certain convertible securities .............. 382,607 318,552 355,577 317,880
Income before dilutive effect of certain convertible
securities, discontinued operations and cumulative effect
of a change in accounting principle ............................ $ 0.38 $ 0.98 $ 0.37 $ 1.61
Dilutive effect of certain convertible securities (1) ........... $ (0.05) $ (0.12) $ -- $ (0.14)
----------- ----------- ----------- -----------
Income before discontinued operations and cumulative effect
of a change in accounting principle ............................ $ 0.33 $ 0.86 $ 0.37 $ 1.47
Income from discontinued operations, net of tax ................. $ 0.03 $ 0.02 $ 0.08 $ 0.10
Cumulative effect of a change in accounting principle ........... $ -- $ -- $ -- $ --
----------- ----------- ----------- -----------
Net income ........................................... $ 0.36 $ 0.88 $ 0.45 $ 1.57
=========== =========== =========== ===========
- ----------
(1) Includes the effect of the assumed conversion of certain dilutive
convertible securities. No convertible securities were included in the
nine months ended September 30, 2002, amounts as the securities were
antidilutive. For the three months ended September 30, 2002, and for the
three and nine months ended September 30, 2001, the assumed conversion
calculation added 99,377, 58,153, and 52,353 shares of common stock and
$14,326, $12,435, and $33,204 to the net income results, respectively.
The accompanying notes are an integral part of these consolidated
condensed financial statements.
-6-
CALPINE CORPORATION AND SUBSIDIARIES
Consolidated Condensed Statements of Cash Flows
For the Nine Months Ended September 30, 2002 and 2001
(In thousands)
(unaudited)
Nine Months Ended
September 30,
2002 2001
----------- ------------
Cash flows from operating activities:
Net income ...................................................................................... $ 159,596 $ 548,127
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization ..................................................... 368,674 242,547
Equipment cancellation cost .................................................................. 172,212 --
Development cost write-off ................................................................... 32,269 --
Deferred income taxes, net ................................................................... 215,296 202,444
Gain on sale of assets ....................................................................... (37,151) (13,514)
(Gain) loss on extinguishment of debt ........................................................ (3,491) 1,803
Minority interests ........................................................................... (2,672) (3,198)
Income from unconsolidated investments in power projects ..................................... (10,499) (9,022)
Distributions from unconsolidated investments in power projects .............................. 2,144 3,596
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable ........................................................................ 107,528 (561,964)
Notes receivable ........................................................................... (35,526) (74,709)
Current derivative assets .................................................................. 206,903 (663,840)
Other current assets ....................................................................... 157,690 (227,058)
Long-term derivative assets ................................................................ 16,442 (541,898)
Other assets ............................................................................... (32,853) (115,203)
Accounts payable and accrued expense ....................................................... (131,292) 421,451
Current derivative liabilities ............................................................. (175,818) (744,322)
Long-term derivative liabilities ........................................................... (273,279) 459,657
Other liabilities .......................................................................... 85,986 1,355,208
Other comprehensive income (loss) relating to derivatives .................................. (37,144) 195,900
----------- -----------
Net cash provided by operating activities ............................................... 785,015 476,005
----------- -----------
Cash flows from investing activities:
Purchases of property, plant and equipment ...................................................... (3,177,525) (5,785,194)
Disposals of property, plant and equipment ...................................................... 125,135 21,898
Advances to joint ventures ...................................................................... (64,707) (103,496)
Increase in notes receivable .................................................................... 8,648 (140,152)
Maturities of collateral securities ............................................................. 4,633 4,035
Project development costs ....................................................................... (84,833) (55,734)
Increase in restricted cash ..................................................................... (14,453) (35,740)
Other ........................................................................................... 5,312 8,384
----------- -----------
Net cash used in investing activities ................................................... (3,197,790) (6,085,999)
----------- -----------
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 ....................................... (869,736) --
Borrowings from notes payable and borrowings under lines of credit .............................. 1,252,453 141,543
Repayments of notes payable and borrowings under lines of credit ................................ (75,734) (444,820)
Borrowings from project financing ............................................................... 438,521 2,324,209
Repayments of project financing ................................................................. (153,827) (1,234,776)
Proceeds from issuance of Convertible Senior Notes Due 2006 ..................................... 100,000 --
Repayments of senior notes ...................................................................... -- (105,000)
Proceeds from senior debt offerings ............................................................. -- 3,853,290
Proceeds from issuance of common stock .......................................................... 755,363 62,283
Proceeds from Income Trust Offering ............................................................. 169,400 --
Financing costs ................................................................................. (71,665) (86,452)
Other ........................................................................................... -- (19,986)
----------- -----------
Net cash provided by financing activities ............................................... 1,544,775 5,490,291
----------- -----------
Effect of exchange rate changes on cash and cash equivalents ....................................... 2,277 --
Net decrease in cash and cash equivalents .......................................................... (865,723) (119,703)
Cash and cash equivalents, beginning of period ..................................................... 1,525,417 596,077
----------- -----------
Cash and cash equivalents, end of period ........................................................... $ 659,694 $ 476,374
=========== ===========
Cash paid during the period for:
Interest, net of amounts capitalized ............................................................ $ 131,760 $ 27,626
Income taxes .................................................................................... $ 14,457 $ 114,667
The accompanying notes are an integral part of these consolidated
condensed financial statements.
-7-
CALPINE CORPORATION AND SUBSIDIARIES
Notes to Consolidated Condensed Financial Statements
September 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"), the adoption
of accounting standards relating to discontinued operations and the presentation
of trading revenue on a net versus gross basis.
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, capitalization of interest 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. Where applicable,
revenues are recognized under Emerging Issues Task Force ("EITF") No. 91-6,
"Revenue Recognition of Long Term Power Sales Contracts," and are recognized
ratably over the terms of the related contracts. 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 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, when
CES does not hold these contracts for trading purposes and, in accordance with
Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements"
and EITF Issue No. 99-19,
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"Reporting Revenue Gross as a Principal Versus Net as an Agent," the Company
records settlement of its non-trading physical forward contracts on a gross
basis. Effective July 1, 2002, the Company now records all gains and losses from
derivatives held for trading purposes on a net basis. Prior to July 1, 2002,
physical trading contracts were recorded on a gross basis but have been
reclassified to a net basis in this filing to conform to the current
presentation. The Company settles its financial swap and option transactions net
and does not take title to the underlying commodity. Accordingly, the Company
records gains and losses from settlement of financial swaps and options net
within net income. Managed risks typically include commodity price risk
associated with fuel purchases and power sales.
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 revenue by occasionally loaning funds to power projects,
by providing operation and maintenance ("O&M") services to third parties and to
certain unconsolidated power projects, and by performing engineering services
for data centers and other facilities requiring highly reliable power. The
Company also has begun to sell engineering and construction services to third
parties for power projects. 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 and sales of purchased power for hedging and optimization. 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 and optimization transactions. CES performs
a market-based allocation of total electric generation and marketing revenue to
electricity and steam sales (based on electricity delivered by the Company's
electric generating facilities) and the balance is allocated to sales of
purchased power.
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 and optimization transactions. Oil and gas sales for produced
products are recognized pursuant to the sales method.
Trading Revenue, Net -- This includes realized settlements of and
unrealized mark-to-market gains and losses on both power and gas derivative
instruments held for trading purposes. Gains and losses due to ineffectiveness
on hedging instruments are also included in unrealized mark-to-market gains and
losses.
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 and optimization activities is
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 fuel expense, while gas purchased from third parties for hedging,
balancing, and optimization activities is 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,
establishes 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.
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
-9-
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.
New Accounting Pronouncements -- In July 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 has not
completed its assessment of the impact of SFAS No. 143.
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 net effect on the
Company's consolidated financial statements, although certain reclassifications
have been made to current and prior period financial statements to reflect the
sale or designation as "held for sale" of certain oil and gas and power plant
assets and classification of the operating results. In general, gains from
completed sales and any anticipated losses on "held for sale" assets (of which
there are none to date) are included in discontinued operations net of tax. See
Note 7 - Discontinued Operations, for further information.
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" and provides
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 Company
has elected early adoption, effective July 1, 2002, of the provisions related to
the rescission of SFAS No. 4, the effect of which has been reflected in these
financial statements as reclassifications of gains and losses from the
extinguishment of debt from extraordinary gain or loss to other
(income)/expense. 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 believes that the SFAS No. 145 provisions
relating to extinguishment of debt may have a material effect on future
presentation of its financial statements but no impact on net income.
-10-
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 EITF 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 other than timing of exit costs,
potentially.
In October 2002 the EITF discussed EITF Issue No. 02-3, "Issues Related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." The EITF reached a consensus to rescind EITF Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," the impact of which is to preclude mark-to-market accounting for
all energy trading contracts not within the scope of SFAS No. 133. The Task
Force also reached a consensus that gains and losses on derivative instruments
within the scope of SFAS No. 133 should be shown net in the income statement if
the derivative instruments are held for trading purposes. The Company expects
that further clarifications may be forthcoming from the EITF on this issue that
could have an affect on the presentation of the Company's financial statements.
The Company has not completed its assessment of the impact that EITF No. 02-3
will have on its financial statements. Effective July 1, 2002, the Company
reclassified certain revenue amounts and cost of revenue in all periods
presented in its Statement of Operations as follows (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- --------------------------
2002 2001 2002 2001
--------- --------- --------- ----------
Amounts previously classified as:
Sales of purchased power ........................................ $ 203,878 $ 373,969 $ 737,921 $ 483,381
Sales of purchased gas .......................................... 54,081 7,851 67,970 16,789
Purchased power expense ......................................... 201,549 369,660 734,616 479,315
Purchased gas expense ........................................... 54,848 6,659 68,517 14,937
Cost of oil and natural gas burned by power plants (fuel
expense) ....................................................... (5,283) (11,199) (12,518) (15,422)
--------- --------- --------- ---------
Net amount reclassified to:
Realized revenue on power and gas trading
transactions, net ........................................... $ 6,845 $ 16,700 $ 15,276 $ 21,340
========= ========= ========= =========
Amounts previously classified as:
Electric power derivative mark-to-market gain (loss) ............ (1,068) 13,577 9,201 83,316
Natural gas derivative mark-to-market gain (loss) ............... (9,889) (6,449) (15,153) 24,546
--------- --------- --------- ---------
Net amount reclassified to:
Unrealized mark-to-market gain (loss) on power and
gas trading transactions, net ............................... $ (10,957) $ 7,128 $ (5,952) $ 107,862
========= ========= ========= =========
Reclassifications -- Prior period amounts in the consolidated condensed
financial statements have been reclassified where necessary to conform to the
2002 presentation.
-11-
3. Property, Plant and Equipment, and Capitalized Interest
Property, plant and equipment, net, consisted of the following (in
thousands):
September 30, December 31,
2002 2001
------------ -------------
Buildings, machinery and equipment ................................... $ 8,655,369 $ 4,743,319
Oil and gas properties, including pipelines .......................... 2,165,849 2,043,296
Geothermal properties ................................................ 395,382 371,156
Other ................................................................ 195,884 114,239
------------ ------------
11,412,484 7,272,010
Less: Accumulated depreciation, depletion and amortization ....... (1,188,406) (849,016)
------------ ------------
10,224,078 6,422,994
Land ................................................................. 77,472 80,506
Construction in progress ............................................. 7,181,850 8,467,580
------------ ------------
Property, plant and equipment, net ................................... $ 17,483,400 $ 14,971,080
============ ============
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 has led to a reduction in the Company's construction
in progress. See Note 13 for further discussion.
As of September 30, 2002, the Company has reclassified $204.4 million of
equipment costs from construction in progress to other assets, as the equipment
is not required for the Company's current power plant development program.
During the year, the Company has recorded a $20.7 million charge to project
development expense to effect a reduction in the carrying value of such
equipment. The Company currently anticipates that some of the equipment will be
used for future power plants and others may be sold to third parties. The
Company is now in negotiations to restructure contracts for certain of its
remaining gas turbines and steam turbines. 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.
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 September 30, 2002 and 2001, the total amount of interest capitalized was
$123.2 million and $121.6 million, including $22.2 million and $29.0 million,
respectively, of interest incurred on funds borrowed for specific construction
projects and $101.0 million and $92.6 million, respectively, of interest
incurred on general corporate funds used for construction. During the nine
months ended September 30, 2002 and 2001, the total amount of interest
capitalized was $457.3 million and $341.2 million, including $94.3 million and
$94.9 million, respectively, of interest incurred on funds borrowed for specific
construction projects and $363.0 million and $246.3 million, respectively, of
interest incurred on general corporate funds used for construction. Upon
commencement of plant operation, capitalized interest, as a component of the
total cost of the plant, is amortized over the estimated useful life of the
plant. The increase in the amount of interest capitalized during 2002, compared
to 2001, reflects the 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
-12-
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
$600 million and $400 million 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 September 30,
-------------------------------------------------------------------------
2002 2001
---------------------------------- ----------------------------------
Per Share Per Share
------------------- -------------------
Amount Diluted Basic Amount Diluted Basic
---------- ------- ------ ---------- ------- -------
Reported income before discontinued operations and
cumulative effect of accounting changes................ $ 144,397 $ 0.33 $ 0.38 $ 313,496 $ 0.86 $ 1.03
Add: Goodwill amortization........................ -- -- -- 221 -- --
Pro forma income before discontinued operations and
cumulative effect of accounting changes................ 144,397 0.33 0.38 313,717 0.86 1.03
Discontinued operations and cumulative effect of
accounting changes, net of tax......................... 16,950 0.03 0.05 7,303 0.02 0.02
---------- ------ ------ ---------- ------ ------
Pro forma net income.............................. $ 161,347 $ 0.36 $ 0.43 $ 321,020 $ 0.88 $ 1.05
========== ====== ====== ========== ====== ======
Nine Months Ended September 30,
-------------------------------------------------------------------------
2002 2001
---------------------------------- ----------------------------------
Per Share Per Share
------------------- -------------------
Amount Diluted Basic Amount Diluted Basic
---------- ------- ------ ---------- ------- -------
Reported income before discontinued operations and
cumulative effect of accounting changes................ $ 132,646 $ 0.37 $ 0.38 $ 510,807 $ 1.47 $ 1.69
Add: Goodwill amortization........................ -- -- -- 562 -- --
Pro forma income before discontinued operations and
cumulative effect of accounting changes................ 132,646 0.37 0.38 511,369 1.47 1.69
Discontinued operations and cumulative effect of
accounting changes, net of tax......................... 26,950 0.08 0.08 37,320 0.10 0.12
---------- ------ ------ ----------- ------ ------
Pro forma net income.............................. $ 159,596 $ 0.45 $ 0.46 $ 548,689 $ 1.57 $ 1.81
========== ====== ====== =========== ====== ======
Recorded goodwill, by segment, as of September 30, 2002 and December 31,
2001, was (in thousands):
September 30, 2002 December 31, 2001
Electric Generation and Marketing....... $ 29,348 $ 29,375
Oil and Gas Production and Marketing.... -- --
Corporate, Other and Eliminations....... -- --
--------- ---------
Total................................ $ 29,348 $ 29,375
========= =========
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.
-13-
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 September 30, 2002 As of December 31, 2001
--------------------------- --------------------------
Weighted
Average
Useful
Life/Contract Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------- ---------- ------------ ---------- ------------
Patents........................................ 5 $ 485 $ (206) $ 485 $ (134)
Power sales agreements......................... 14 159,563 (103,874) 159,563 (86,646)
Fuel supply and fuel management contracts...... 26 22,198 (3,882) 22,198 (3,216)
Geothermal lease rights........................ 20 19,493 (325) 19,493 (250)
Steam purchase agreement....................... 14 5,073 (386) - -
Other.......................................... 5 852 (58) 277 (25)
---------- ---------- ---------- ----------
Total....................................... $ 207,664 $ (108,731) $ 202,016 $ (90,271)
========== ========== ========== ==========
Amortization expense of other intangible assets was $6.4 million and $5.9
million in the three months ended September 30, 2002 and 2001, respectively, and
$18.5 million and $17.8 million in the nine months ended September 30, 2002 and
2001, respectively. Assuming no future impairments of these assets or additions
as the result of acquisitions, annual amortization expense will be $21.7 million
for the twelve months ended December 31, 2002, $5.5 million in 2003, $5.0
million in 2004, $5.0 million in 2005 and $4.9 million in 2006.
5. 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
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 September 30, 2002, there was $117.5 million in borrowings outstanding
under this agreement.
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. $50.0 million was repaid on August 7, 2002,
and the remaining $50.0 million (which is classified as current project
financing) is payable on November 25, 2002.
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 aggregate size of its
secured corporate revolving credit facilities to $1.0 billion (the $600 million
and $400 million facilities, respectively,) from $1.4 billion. At September 30,
2002, the Company had $1.0 billion in funded borrowings outstanding under the
term loan facility, and $250.0 million in funded borrowings outstanding, and
$595.2 million in outstanding letters of credit under the revolving credit
facilities. The revolving credit facilities expire in 2003. However, any letters
of credit under the $600 million revolving credit facility can be extended for
one year at the Company's option. In 2004 the $1 billion term loan matures.
On August 22, 2002, the Company completed a $106 million non-recourse
project financing for the construction of its 300 megawatt Blue Spruce Energy
Center. At September 30, 2002, the Company had $47.2 million in funded
borrowings under this non-recourse construction and term-loan facility.
In November 2003 and 2004 the Company's $1.0 billion and $2.5 billion
secured revolving construction financing facilities will mature, requiring the
Company to repay or refinance this indebtedness. At September 30, 2002, there
was $969.8 million and $2,493.6 million outstanding, respectively, under these
facilities.
For financing activity subsequent to September 30, 2002, see Note 15 -
Subsequent Events.
-14-
6. Canadian Income Trust
On August 29, 2002, the Company announced it had completed a Cdn$230
million (US$147.5 million) initial public offering of its Canadian income trust
fund - Calpine Power Income Fund (the "Fund"). The 23 million Trust Units issued
to the public were priced at Cdn$10.00 per unit, to initially yield 9.35% per
annum. The Fund indirectly owns interests in two of Calpine's Canadian power
generating assets, one of which is under construction, and will make a loan to a
Calpine subsidiary which owns Calpine's other Canadian power generating asset.
Combined, these assets represent approximately 550 net megawatts of power
generating capacity.
On September 20, 2002, the syndicate of underwriters fully exercised the
over-allotment option that it was granted as part of the initial public offering
of Trust Units and acquired 3,450,000 additional Trust Units of the Fund at
Cdn$10 per Trust Unit, generating Cdn$34.5 million (US$21.9 million). This
brings the total gross amount of the initial public offering to Cdn$264.5
million (US$169.4 million) as of September 30, 2002.
The Company intends to retain a substantial interest and operating and
management role in the Calpine Power Income Fund and the Fund assets and,
accordingly, the financial results of the Fund are consolidated in the Company's
financial statements. At September 30, 2002, the Company held 49% of the Fund's
authorized Trust Units. The proceeds from the public offering of Trust Units
were recorded as minority interests in the Company's balance sheet.
7. Discontinued Operations
As a result of the significant contraction in the availability of capital
for participants in the energy sector, the Company has adopted a strategy of
conserving its core strategic assets. Implicit within this strategy is the
disposal of certain assets, which serves primarily to strengthen the Company's
balance sheet through repayment of debt. Set forth below are all of the
Company's announced and/or completed asset disposals by reportable segment as of
September 30, 2002:
Oil and Gas Production and Marketing
On August 29, 2002, the Company completed the sale of certain non-strategic
oil and gas properties ("Medicine River properties") located in central Alberta
to NAL Oil and Gas Trust and another institutional investor for Cdn$125 million
(US$81 million).
In September 2002 the Company announced an agreement with Pengrowth
Corporation, administrator of Pengrowth Energy Trust, to sell substantially all
of the Company's British Columbia oil and gas properties. The sale was
subsequently completed on October 1, 2002, for approximately Cdn$387.5 million
(US$243.7 million). See Note 15 - Subsequent Events - for further discussion.
In September 2002 the Company executed a Purchase and Sale Agreement with
Goldking Energy Corporation to sell all of the oil and gas properties in Drake
Bay Field located in Plaquemines Parish, Louisiana for approximately $3 million.
The sale was subsequently completed on October 31, 2002.
Electric Generation and Marketing
On June 28, 2002, the Company executed a definitive agreement with
Wisconsin Public Service for the sale to Wisconsin Public Service of the
Company's 180-megawatt DePere Energy Center. The closing of this transaction is
subject to certain conditions. One of the conditions, the receipt of regulatory
approval by the State of Wisconsin, was satisfied on September 16, 2002. The
sale is expected to close during the fourth quarter of 2002. Upon completion of
the sale, Wisconsin Public Service will pay the Company $120.4 million for the
DePere facility, and the existing power purchase agreement will be terminated.
-15-
The tables below present significant components of the Company's income
from discontinued operations for the three and nine months ended 2002 and 2001,
respectively (in thousands):
Three Months Ended September 30, 2002 Three Months Ended September 30, 2001
------------------------------------------- ------------------------------------------
Electric Oil and Gas Electric Oil and Gas
Generation Production Generation Production
and Marketing and Marketing Total and Marketing and Marketing Total
------------- ------------- -------- ------------- ------------- --------
Total revenue...................... $ 4,440 $26,369 $ 30,809 $ 4,463 $ 30,168 $ 34,631
Gain on disposal before taxes...... -- 22,996 22,996 -- -- --
Income from discontinued
operations before taxes........... 588 26,037 26,625 35 12,171 12,206
Income from discontinued
operations, net of tax............ 287 16,663 16,950 20 7,283 7,303
Nine Months Ended September 30, 2002 Nine Months Ended September 30, 2001
------------------------------------------- ------------------------------------------
Electric Oil and Gas Electric Oil and Gas
Generation Production Generation Production
and Marketing and Marketing Total and Marketing and Marketing Total
------------- ------------- -------- ------------- ------------- --------
Total revenue...................... $ 10,091 $73,931 $ 84,022 $ 10,936 $117,926 $128,862
Gain on disposal before taxes...... -- 22,996 22,996 -- -- --
Income from discontinuing
operations before taxes........... 1,858 40,151 42,009 (293) 60,951 60,658
Income from discontinued
operations, net of tax............ 1,112 25,838 26,950 (177) 36,461 36,284
The table below presents the assets and liabilities held for sale on the
Company's balance sheet as of September 30, 2002 and December 31, 2001,
respectively:
September 30, 2002 December 31, 2001
------------------------------------------- ------------------------------------------
Electric Oil and Gas Electric Oil and Gas
Generation Production Generation Production
and Marketing and Marketing Total and Marketing and Marketing Total
------------- ------------- -------- ------------- ------------- --------
Current assets held for sale....... $ -- $ 19,920 $ 19,920 $ -- $ 9,484 $ 9,484
Long-term assets held for sale..... 76,489 164,985 241,474 70,304 238,159 308,463
-------- -------- -------- -------- -------- --------
Total assets held for sale....... $ 76,489 $184,905 $261,394 $ 70,304 $247,643 $317,947
======== ======== ======== ======== ======== ========
Current liabilities held for sale.. $ -- $ 4,522 $ 4,522 $ -- $ 4,576 $ 4,576
Long-term liabilities held for sale 5,983 -- 5,983 5,947 -- 5,947
-------- -------- -------- -------- -------- --------
Total liabilities held for sale.. $ 5,983 $ 4,522 $ 10,505 $ 5,947 $ 4,576 $ 10,523
======== ======== ======== ======== ======== ========
The Company allocates interest expense associated with consolidated
non-specific debt to its discontinued operations based on a ratio of the net
assets of its discontinued operations to the Company's total consolidated net
assets, in accordance with EITF Issue No. 87-24, "Allocation of Interest to
Discontinued Operations" ("EITF No. 87-24"). Also in accordance with EITF No.
87-24, the Company allocated interest expense to its British Columbia oil and
gas properties for approximately $50.4 million of debt the Company is required
to repay under the terms of its $1.0 billion term loan. For the three months
ended September 30, 2002 and 2001, the Company allocated interest expense of
$2.8 million and $1.3 million, respectively, to its discontinued operations. For
the nine months ended September 30, 2002 and 2001, the Company allocated
interest expense of $5.8 million and $3.1 million, respectively, to its
discontinued operations.
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
-16-
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.
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.
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 September 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.......................... $ -- $ -- $ 556,259 $ 556,259
Long-term derivative assets........................ -- -- 548,510 548,510
----------- ----------- ----------- -----------
Total assets.................................... $ -- $ -- $ 1,104,769 $ 1,104,769
=========== =========== =========== ===========
Current derivative liabilities..................... $ 13,486 $ 2,645 $ 433,390 $ 449,521
Long-term derivative liabilities................... 28,881 10,992 509,696 549,569
----------- ----------- ----------- -----------
Total liabilities............................... $ 42,367 $ 13,637 $ 943,086 $ 999,090
=========== =========== =========== ===========
Net derivative assets (liabilities).......... $ (42,367) $ (13,637) $ 161,683 $ 105,679
=========== =========== =========== ===========
-17-
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.
o Derivatives not designated as cash flow hedges and hedge
ineffectiveness -- Only derivatives that qualify as effective cash
flow hedges will have an offsetting amount recorded in OCI.
Derivatives not designated as cash flow hedges and the ineffective
portion of derivatives designated as cash flow hedges will be recorded
into earnings instead of OCI, creating a difference between net
derivative assets and liabilities and pre-tax OCI from derivatives.
o Termination of effective cash flow hedges prior to maturity --
Following the termination of a cash flow hedge, changes in the
derivative asset or liability are no longer recorded to OCI. At this
point, an accumulated OCI balance remains that 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
September 30, 2002 (in thousands):
Net derivative assets......................................................................... $ 105,679
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness........... (170,507)
Cash flow hedges terminated prior to maturity................................................. (283,448)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges... 126,305
Accumulated OCI from unconsolidated investees................................................. 16,625
Other reconciling items....................................................................... 2,108
----------
Accumulated other comprehensive loss from derivative instruments, net of tax.................. $ (203,238)
==========
The asset and liability balances for the Company's commodity derivative
instruments represent the net totals after offsetting certain assets against
certain liabilities under the criteria of FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB
Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract,
FIN 39 will allow the offsetting of assets against liabilities so long as four
criteria are met: (1) each of the two parties under contract owes the other
determinable amounts; (2) the party reporting under the offset method has the
right to set off the amount it owes against the amount owed to it by the other
party; (3) the party reporting under the offset method intends to exercise its
right to set off; and; (4) the right of set-off is enforceable by law. The table
below reflects both the amounts (in thousands) recorded as assets and
liabilities by the Company and the amounts that would have been recorded had the
Company's commodity derivative instrument contracts not qualified for offsetting
as of September 30, 2002.
September 30, 2002
------------------------------
Gross Net
------------ ------------
Current derivative assets.................... $ 884,615 $ 556,259
Long-term derivative assets.................. 682,683 548,510
------------ ------------
Total derivative assets................... $ 1,567,298 $ 1,104,769
============ ============
Current derivative liabilities............... $ 761,746 $ 433,390
Long-term derivative liabilities............. 643,869 509,696
------------ ------------
Total derivative liabilities.............. $ 1,405,615 $ 943,086
============ ============
Net commodity derivative assets........ $ 161,683 $ 161,683
============ ============
The table above excludes the value of interest rate and currency derivative
instruments.
-18-
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 nine months ended September 30, 2002 and 2001, respectively
(in thousands):
Three Months Ended September 30,
--------------------------------------------------------------------------------------------
2002 2001
-------------------------------------------- ---------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ --------- --------------- ------------ --------
Natural gas derivatives............ $(2,141) $(7,748) $ (9,889) $(2,346) $(4,103) $(6,449)
Power derivatives.................. (3,072) 2,004 (1,068) -- 13,577 13,577
Interest rate derivatives (1)...... (236) -- (236) (95) -- (95)
------- ------- -------- ------- ------- -------
Total........................... $(5,449) $(5,744) $(11,193) $(2,441) $ 9,474 $ 7,033
======= ======= ======== ======= ======= =======
Nine Months Ended September 30,
--------------------------------------------------------------------------------------------
2002 2001
-------------------------------------------- ---------------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ --------- --------------- ------------ --------
Natural gas derivatives............ $ 584 $(15,737) $(15,153) $(5,818) $ 30,364 $ 24,546
Power derivatives.................. (4,296) 13,497 9,201 -- 83,316 83,316
Interest rate derivatives (1)...... (577) -- (577) (112) -- (112)
------- -------- -------- ------- -------- --------
Total........................... $(4,289) $ (2,240) $ (6,529) $(5,930) $113,680 $107,750
======= ======== ======== ======= ======== ========
- ----------
(1) Recorded within Other Income
The table below reflects the contribution of the Company's cash flow hedge
activity to pre-tax earnings based on the reclassification adjustment from OCI
to earnings for the three and nine months ended September 30, 2002 and 2001,
respectively (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
Natural gas and crude oil derivatives .................. $ (43,224) $ (25,913) $(118,267) $ 2,067
Power derivatives ...................................... 90,747 126,930 252,527 120,742
Interest rate derivatives .............................. (3,385) (9,085) (8,012) (9,085)
Foreign currency derivatives ........................... -- -- (2,794) --
--------- --------- --------- ---------
Total derivatives ................................... $ 44,138 $ 91,932 $ 123,454 $ 113,724
========= ========= ========= =========
As of September 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 8, 6 1/2, and 12 years, for commodity, foreign currency and
interest rate derivative instruments, respectively. The Company estimates that
pre-tax losses of $87.5 million would be reclassified from accumulated OCI into
earnings during the twelve months ended September 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.
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.
-19-
2007
Q4 2002 2003 2004 2005 2006 & After Total
---------- ---------- ---------- ---------- ---------- ---------- ----------
Crude oil OCI (1) ................ $ (2,614) $ (1,763) $ -- $ -- $ -- $ -- $ (4,377)
Gas OCI .......................... (1,607) (145,939) (62,061) (61,243) (26,978) 2,842 (294,986)
Power OCI ........................ 21,767 51,765 7,332 1,827 3,651 (1,149) 85,193
Interest rate OCI ................ (16,128) (18,091) (14,539) (11,995) (10,303) (29,965) (101,021)
Foreign currency OCI ............. (144) (2,034) (2,004) (1,973) (1,966) (6,233) (14,354)
--------- --------- --------- --------- --------- --------- ---------
Total pre-tax OCI ............. $ 1,274 $(116,062) $ (71,272) $ (73,384) $ (35,596) $ (34,505) $(329,545)
========= ========= ========= ========= ========= ========= =========
- ----------
(1) Amounts in crude oil OCI relate to certain of the Company's oil and gas
discontinued operations. These amounts will continue to be recognized into
income from discontinued operations until the disposals have been
completed. See Note 7 - Discontinued Operations - for further discussion.
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 September 30, 2002
--------------------------------------------------------------------
Cash Flow Foreign Currency Comprehensive
Hedges Translation Total Income (Loss)
----------- ---------------- ----------- -------------
Accumulated other comprehensive loss at
December 31, 2001............................................ $ (183,377) $ (43,197) $ (226,574)
Net loss for the three months ended March 31, 2002............ $ (74,267)
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
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)
========== ========== ==========
(continues next page)
-20-
Accumulated Other Comprehensive Income (Loss)
At September 30, 2002
--------------------------------------------------------------------
Cash Flow Foreign Currency Comprehensive
Hedges Translation Total Income (Loss)
----------- ---------------- ----------- -------------
Net income for the three months ended September 30, 2002...... $ 161,347
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the three
months ended September 30, 2002........................ $ (74,813)
Reclassification adjustment for gain included
in net income for the three months ended
September 30, 2002..................................... (44,138)
Income tax benefit for the three months ended
September 30, 2002..................................... 44,830
----------
(74,121) $ (74,121) (74,121)
Foreign currency translation loss for the three months
ended September 30, 2002.................................. $ (37,489) (37,489) (37,489)
---------- ---------- ---------- ----------
Total comprehensive income for the three months ended
September 30, 2002........................................... 49,737
----------
Total comprehensive income for the nine months ended
September 30, 2002........................................... $ 155,853
==========
Accumulated other comprehensive loss at
September 30, 2002........................................... $ (203,238) $ (27,079) $ (230,317)
========== ========== ==========
Accumulated Other Comprehensive Income (Loss)
At September 30, 2001
--------------------------------------------------------------------
Cash Flow Foreign Currency Comprehensive
Hedges Translation Total Income (Loss)
----------- ---------------- ----------- -------------
Accumulated other comprehensive loss at
December 31, 2000............................................ $ -- $ (23,085) $ (23,085)
Net loss for the three months ended March 31, 2001 $ 119,663
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
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 at June 30, 2001....... $ 103,352 $ (24,941) $ 78,411
========== ========== ==========
(continues next page)
-21-
Accumulated Other Comprehensive Income (Loss)
At September 30, 2002
--------------------------------------------------------------------
Cash Flow Foreign Currency Comprehensive
Hedges Translation Total Income (Loss)
----------- ---------------- ----------- -------------
Net income for the three months ended September 30, 2001...... $ 320,799
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the three
months ended September 30, 2001........................ $ (387,558)
Reclassification adjustment for gain included
in net income for the three months ended
September 30, 2001..................................... (91,932)
Income tax benefit for the three months ended
September 30, 2001..................................... 188,578
----------
(290,912) $ (290,912) (290,912)
Foreign currency translation loss for the three months
ended September 30, 2001.................................. $ (10,659) (10,659) (10,659)
---------- ---------- ---------- ----------
Total comprehensive income for the three months ended
September 30, 2001........................................... 19,228
----------
Total comprehensive income for the nine months ended
September 30, 2001........................................... $ 348,052
==========
Accumulated other comprehensive loss at
September 30, 2001........................................... $ (187,560) $ (35,600) $ (223,160)
========== ========== ==========
10. Customers
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 requested that its power suppliers extend payment
terms to help it overcome its short-term liquidity problems. In June and July
2002 NPC underpaid the Company by approximately $4.2 million, and the Company
established a bad debt reserve of approximately $2.7 million against NPC
receivables. 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. In September, 2002, NPC notified the Company of its
intention to repay all outstanding payables owed to the Company for power
deliveries made during the period of May 1, 2002 through September 15, 2002,
following execution by the Company of an agreement to forebear from taking
action against NPC provided NPC makes certain periodic payments. On October 25,
2002, the Company received approximately $22.2 million from NPC as repayment of
past due amounts for power deliveries through September 15, 2002.
As of September 30, 2002, the Company had net collection exposures of
approximately $35.1 million and $9.6 million with NPC and SPPC, respectively.
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 September 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........................... $ 42.7 $ (14.8) $ 27.9 $ 20.1 $ (12.9) $ 7.2 $ 35.1
SPPC.......................... 6.3 -- 6.3 3.3 -- 3.3 9.6
------- ------- ------- ------- ------- ------- -------
Total...................... $ 49.0 $ (14.8) $ 34.2 $ 23.4 $ (12.9) $ 10.5 $ 44.7
======= ======= ======= ======= ======= ======= =======
-22-
Under the terms of its contracts with NPC and SPPC, the Company believes
that it has the right to offset asset and liability positions.
NRG Power Marketing, Inc.
The Company has open contract positions with NRG Power Marketing, Inc., a
subsidiary of NRG Energy, Inc., which in turn is the unregulated
power-generation subsidiary of XCEL Energy Inc. Almost all of the open contracts
are accounted for as cash flow hedges under SFAS No. 133. NRG Energy, Inc. has
reportedly experienced financial problems, defaulted on certain loan payments
and has had its long-term debt rating downgraded to D by Standard & Poor's.
According to a report published on November 8, 2002, NRG Energy, Inc. has
discussed a Chapter 11 bankruptcy filing with its lenders. While NRG Power
Marketing, Inc. has remained current in its payments to the Company through
October 20, 2002, the Company has established a partial reserve in OCI in the
balance sheet against the fair value of its open contract position with NRG
Power Marketing, Inc. The Company will continue to closely monitor its position
with NRG Power Marketing, Inc. and will adjust the value of the reserve as
conditions dictate. The Company's exposure, net of the established reserve, to
NRG Power Marketing, Inc. at September 30, 2002, is summarized below (in
millions):
Receivables/Payables Open Positions
--------------------------------------- --------------------------------------
Net Gross Gross Net Open
Gross Gross Receivable Fair Value Fair Value Positions
Receivable Payable (Payable) (+) (-) Value Total
---------- -------- ---------- ---------- ---------- --------- --------
NRG Power Marketing, Inc...... $ 3.0 $ (0.0) $ 3.0 $ 6.3 $ (0.5) $ 5.8 $ 8.8
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 $6
million, with no payments 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 has also filed for insolvency. However, the
Dutch company has assured the Company that it has not and currently does not
expect to file for insolvency. 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, the
Company has not established a reserve against the related receivable but will
continue to closely monitor the situation.
Aquila Merchant Services, Inc.
On November 13th, Aquila Inc. ("Aquila"), the parent of Aquila Merchant
Services, Inc., ("AMS"), reported third quarter 2002 losses of approximately
$332 million, suspended its dividend and disclosed that it had obtained debt
covenant waivers expiring in April 2003 from certain of its lenders. Currently
Aquila has an investment grade rating with two of the three major credit rating
agencies. We believe that a downgrade in Aquila's credit rating could trigger
additional collateral requirements under Aquila's and AMS's contractual
commitments. We currently buy and sell electricity and natural gas from Aquila
and AMS under a variety of contractual arrangements. We account for certain of
our contractual arrangements with AMS as derivatives under SFAS No. 133 and,
accordingly, record the fair value of the open positions under these contracts
in our financial statements. We also have tolling arrangements with AMS on our
Acadia facility and with Aquila on our Aries facility under which they deliver
gas to, and purchase electricity from, us with 20 and 15.5 year terms,
respectively. These tolling agreements are not subject to derivative accounting.
We also have outstanding receivable and payable balances with Aquila and AMS.
The net value of the positions in our balance sheet at September 30, 2002, is
summarized below (in millions):
Receivables/Payables Open Positions
--------------------------------------- --------------------------------------
Net Gross Gross Net Open
Gross Gross Receivable Fair Value Fair Value Positions
Receivable Payable (Payable) (+) (-) Value Total
---------- -------- ---------- ---------- ---------- --------- --------
AMS and Aquila................ $ 4.0 $ (10.6) $ (6.6) $ 53.8 $ (5.1) $ 48.7 $ 42.1
-23-
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 each counterparty's credit rating and
evaluation of the financial statements. The credit department monitors these
thresholds to determine the need for additional collateral or restriction of
activity with the counterparty.
11. Earnings Per Share
Basic earnings per common share were computed by dividing net income 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 per common share to diluted earnings per
share is shown in the following table (in thousands, except per share data).
Periods Ended September 30,
--------------------------------------------------------------------------
2002 2001
---------------------------------- -----------------------------------
Net Net
Income Shares EPS Income Shares EPS
---------- -------- ------ --------- -------- -------
THREE MONTHS:
Basic earnings per common share:
Income before discontinued operations and
cumulative effect of a change in accounting
principle......................................... $ 144,397 376,957 $ 0.38 $ 313,496 304,666 $ 1.03
Discontinued operations, net of tax................ 16,950 0.05 7,303 0.02
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- -- -- --
---------- -------- ------ --------- -------- -------
Net income.................................... $ 161,347 376,957 $ 0.43 $ 320,799 304,666 $ 1.05
========== -------- ====== ========= -------- =======
Diluted earnings per common share:
Common shares issuable upon exercise of stock
options using treasury stock method............... 5,650 13,886
-------- --------
Income before dilutive effect of certain
convertible securities, discontinued operations
and cumulative effect of a change in accounting
principle......................................... $ 144,397 382,607 0.38 $ 313,496 318,552 $ 0.98
Dilutive effect of certain convertible securities.. 14,326 99,377 (0.05) 12,435 58,153 (0.12)
---------- -------- ------ --------- -------- -------
Income before discontinued operations and
cumulative effect of a change in accounting
principle......................................... 158,723 481,984 0.33 325,931 376,705 0.86
Discontinued operations, net of tax................ 16,950 0.03 7,303 0.02
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- -- -- --
---------- -------- ------ --------- -------- -------
Net income.................................... $ 175,673 481,984 $ 0.36 $ 333,234 376,705 $ 0.88
========== ======== ====== ========= ======== =======
-24-
Periods Ended September 30,
--------------------------------------------------------------------------
2002 2001
---------------------------------- -----------------------------------
Net Net
Income Shares EPS Income Shares EPS
---------- -------- ------ --------- -------- -------
NINE MONTHS:
Basic earnings per common share:
Income before discontinued operations and
cumulative effect of a change in accounting
principle......................................... $ 132,646 346,816 $ 0.38 $ 510,807 302,649 $ 1.69
Discontinued operations , net of tax............... 26,950 0.08 36,284 0.12
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- 1,036 -- --
---------- -------- ------ --------- -------- -------
Net income.................................... $ 159,596 346,816 $ 0.46 $ 548,127 302,649 $ 1.81
========== -------- ====== ========= -------- =======
Diluted earnings per common share:
Common shares issuable upon exercise of stock
options using treasury stock method............... 8,761 15,231
-------- --------
Income before dilutive effect of certain
convertible securities, discontinued operations
and cumulative effect of a change in accounting
principle......................................... $ 132,646 355,577 $ 0.37 $ 510,807 317,880 $ 1.61
Dilutive effect of certain convertible securities.. -- -- -- 33,204 52,353 (0.14)
---------- -------- ------ --------- -------- -------
Income before discontinued operations and
cumulative effect of a change in accounting
principle......................................... 132,646 355,577 0.37 544,011 370,233 1.47
Discontinued operations, net of tax................ 26,950 0.08 36,284 0.10
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- 1,036 -- --
---------- -------- ------ --------- -------- -------
Net income.................................... $ 159,596 355,577 $ 0.45 $ 581,331 370,233 $ 1.57
========== ======== ====== ========= ======== =======
For the three and nine months ended September 30, 2002 and for the three
and nine months ended September 30, 2001, respectively, the effect of 28,149,
124,755, 2,693 and 2,683 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." On August 27, 2002, the Company
announced that, effective January 1, 2003, we intended to adopt SFAS No. 123,
"Accounting for Stock-Based Compensation." Had compensation cost been determined
consistent with the methodology of SFAS No. 123, which provides for the
accounting of options as compensation expense, the Company's net income and
earnings per share would have been changed to the following pro forma amounts
(in thousands, except per share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- ---------------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Net income
As reported............................................ $ 161,347 $ 320,799 $ 159,596 $ 548,127
Pro Forma.............................................. 155,020 312,922 127,934 527,042
Earnings per share data:
Basic earnings per share
As reported............................................ $ 0.43 $ 1.05 $ 0.46 $ 1.81
Pro Forma.............................................. 0.41 1.03 0.37 1.74
Diluted earnings per share
As reported............................................ $ 0.36 $ 0.88 $ 0.45 $ 1.57
Pro Forma.............................................. 0.35 0.86 0.36 1.51
For the three and nine months ended September 30, 2002 and 2001,
respectively, the fair value of options granted was $3.56 and $5.09, and $13.79
and $22.67 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 nine months ended September 30,
-25-
2002, and 76% for the three and nine months ended September 30, 2001, risk-free
interest rates of 2.34% for the three months ended September 30, 2002, 2.66% for
the nine months ended September 30, 2002, and 5.02% for the three and nine
months ended September 30, 2001, and expected option terms after vesting of 2
years and 3 years for the three and nine months ended September 30, 2002 and 1
year for the three and nine months ended September 30, 2001.
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. 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. The Company recorded an additional pre-tax
charge of $3.7 million in the third quarter of 2002, based on final resolution
of this cancellation.
Discussions continue with certain of the Company's major equipment
manufacturers to restructure its existing orders for gas and steam turbines. The
Company expects to complete this process by the end of 2002.
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
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 as defendants the Company, certain of its officers
and directors, and the underwriters of the offering, 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.
-26-
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 and its subsidiaries
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
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 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.
-27-
14. Operating Segments
The Company's primary operating segments are power generation; oil and gas
production and marketing; and corporate activities and other. Power generation
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. This presentation
constitutes a change from prior presentation in that management reviews results
from segments inclusive of hedging activity, in contrast to the prior view of
hedging activity along product line (gas hedging for power plants is now in
power generation, versus oil and gas production and marketing). 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 gross profit, which is reflected below.
Oil and Gas
Power Production Corporate, Other
Generation and Marketing and Eliminations Total
----------------------- -------------------- --------------------- ----------------------
2002 2001 2002 2001 2002 2001 2002 2001
---------- ---------- ---------- -------- ---------- --------- ---------- ----------
(in thousands)
For the three months ended
September 30, 2002 and 2001:
Revenue............................ $2,412,458 $2,465,384 $ 88,201 $ 62,185 $ (5,649) $ (7,418) $2,495,010 $2,520,151
Gross profit....................... 352,601 497,879 10,869 16,762 (1,138) 6,504 362,332 521,145
Income (loss) before provision
for taxes......................... 292,317 478,888 9,993 10,894 (109,507) (36,982) 192,803 452,800
Discontinued operations,
net of tax........................ 287 20 16,663 7,283 -- -- 16,950 7,303
Merger expense..................... -- -- -- -- -- -- -- --
Equipment cancellation cost........ 3,714 -- -- -- -- -- 3,714 --
Oil and Gas
Power Production Corporate, Other
Generation and Marketing and Eliminations Total
----------------------- -------------------- --------------------- ----------------------
2002 2001 2002 2001 2002 2001 2002 2001
---------- ---------- ---------- -------- ---------- --------- ---------- ----------
(in thousands)
For the nine months ended
September 30, 2002 and 2001:
Revenue............................ $5,331,664 $5,063,070 $ 249,588 $340,696 $ 5,490 $ (99,000) $5,586,742 $5,304,766
Gross profit....................... 754,348 865,388 37,910 190,080 (14,917) (7,384) 777,341 1,048,084
Income (loss) before provision
for taxes......................... 517,185 795,509 (40,159) 131,850 (305,575) (138,391) 171,451 788,968
Discontinued operations,
net of tax........................ 1,112 (177) 25,838 36,461 -- -- 26,950 36,284
Merger expense..................... -- -- -- 41,627 -- -- -- 41,627
Equipment cancellation cost........ 172,185 -- -- -- -- -- 172,185 --
Oil and Gas
Power Production Corporate, Other
Generation and Marketing and Eliminations Total
----------- ------------- ---------------- -----------
(in thousands)
Total assets:
September 30, 2002 ..................... $18,334,658 $ 4,061,421 $ 293,247 $22,689,326
December 31, 2001 ...................... $12,572,848 $ 3,503,075 $ 5,253,629 $21,329,552
For the three months ended September 30, 2002 and 2001, there were
intersegment revenues of approximately $144.9 million and $15.9 million,
respectively. For the nine months ended September 30, 2002 and 2001, there were
intersegment revenues of approximately $217.3 million and $100.8 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.
-28-
15. Subsequent Events
In October 2002 the Company completed the sale of substantially all of its
British Columbia oil and gas properties to Calgary, Alberta-based Pengrowth
Corporation for gross proceeds of approximately Cdn$387.5 million (US$243.7
million). Of the total consideration, the Company received US$155.3 million in
cash. The remaining US$88.4 million was paid by Pengrowth Corporation's purchase
in the open market (for an aggregate purchase price of US$88.4 million) and
delivery to the Company of US$203.2 million in aggregate principal amount of the
Company's debt securities. As a result of the transaction, the Company will
record a US$41.5 million pre-tax gain on the sale of the properties before any
gains on the repurchase of debt. The Company used approximately US$50.4 million
of proceeds to repay amounts outstanding under its US$1.0 billion term loan.
The debt securities delivered to the Company by Pengrowth Corporation
comprised:
Debt Security Principal Amount
----------------------------------------- ----------------
7-7/8% Senior Notes Due 2008............. $ 19.5 million
7-3/4% Senior Notes Due 2009............. 20.2 million
8-5/8% Senior Notes Due 2010............. 42.4 million
8-1/2% Senior Notes Due 2011............. 121.1 million
---------------
Total................................. $ 203.2 million
===============
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
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 operational 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 November 14, 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:
-29-
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 nine months ended September 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 Nine Months Ended
September 30, September 30,
----------------------------- ------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(in thousands, except production and pricing data)
Power Plants:
Electricity and steam ("E&S") revenue:
Energy................................................. $ 485,431 $ 488,621 $ 1,542,957 $ 1,266,601
Capacity............................................... 409,115 177,928 600,955 420,138
Thermal and other...................................... 52,780 43,957 125,980 118,150
------------ ------------ ------------ ------------
Subtotal............................................. $ 947,326 $ 710,506 $ 2,269,892 $ 1,804,889
E&S revenue from discontinued operations.................. 4,440 4,463 10,091 10,936
Spread on sales of purchased power (1).................... 223,136 258,217 486,601 283,684
------------ ------------ ------------ ------------
Adjusted E&S revenue...................................... $ 1,174,902 $ 973,186 $ 2,766,584 $ 2,099,509
Megawatt hours produced................................... 23,375,000 13,687,000 53,809,000 28,804,000
All-in electricity price per megawatt hour generated...... $ 50.26 $ 71.10 $ 51.41 $ 72.89
- ------------
(1) From hedging, balancing and optimization activities related to our
generating assets. The spread on trading activities is excluded.
Credit restrictions on certain Calpine Energy Services, L.P. ("CES")
activities in 2002 has negatively impacted the volume of its hedging, balancing
and optimization activities and these restrictions could cause further
reductions of such activities in the future.
Megawatt hours produced at the power plants increased 71% and 87% for the
three and nine months ended September 30, 2002, as compared to the same periods
in 2001. This was primarily due to the addition of power plants that commenced
commercial operation subsequent to September 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.
Results of Operations
Set forth below is a table summarizing the dollar amounts and percentages
of our total revenue for the three and nine months ended September 30, 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):
-30-
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- ------------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Total revenue................................................. $ 2,495,010 $ 2,520,151 $ 5,586,742 $ 5,304,766
Sales of purchased power for hedging and optimization......... 1,282,976 1,653,088 2,526,555 2,680,488
As a percentage of total revenue.............................. 51.4% 65.6% 45.2% 50.5%
Sales of purchased gas for hedging and optimization........... 231,893 56,916 666,095 412,782
As a percentage of total revenue.............................. 9.3% 2.3% 11.9% 7.8%
Total cost of revenue ("COR")................................. 2,132,678 1,999,006 4,809,401 4,256,682
Purchased power expense for hedging and optimization.......... 1,059,840 1,394,871 2,039,954 2,396,804
As a percentage of total COR.................................. 49.7% 69.8% 42.4% 56.3%
Purchased gas expense for hedging and optimization............ 220,775 52,856 678,192 389,814
As a percentage of total COR.................................. 10.4% 2.6% 14.1% 9.2%
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 physical delivery hedging contracts on
a gross basis (as opposed to netting sales and cost of revenue).
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 Nine Months Ended
September 30, September 30,
--------------------------- ----------------------------
2002 2001 2002 2001
---------- ---------- ---------- ----------
(in thousands)
Sales into NEPOOL ISO from power we generated................ $ 97,852 $ 99,819 $ 211,889 $ 221,275
Sales into NEPOOL ISO from hedging and other activity........ 33,964 67,776 78,770 124,420
---------- ---------- ---------- ----------
Total sales into NEPOOL................................... $ 131,816 $ 167,595 $ 290,659 $ 345,695
Total purchases from NEPOOL ISO........................... $ 113,659 $ 152,463 $ 274,838 $ 319,023
Three Months Ended September 30, 2002, Compared to Three Months Ended September
30, 2001.
Revenue -- Total revenue decreased slightly to $2,495.0 million for the
three months ended September 30, 2002, compared to $2,520.2 million for the same
period in 2001.
Electric generation and marketing revenue decreased to $2,230.3 million in
2002 compared to $2,363.6 million in 2001. Approximately $236.8 million of the
$133.3 million variance was due to electricity and steam sales, which increased
due to our growing portfolio of power plants. Generation increased 71% but
average pricing dropped by 29%. Our revenue for the period ended September 30,
2002, includes the consolidated results of additional facilities that we
completed construction on subsequent to September 30, 2001. However, sales of
purchased power decreased by $370.1 million due to lower power prices and
industry-wide credit restrictions on risk management activities in 2002, which
has resulted in a lower volume of hedging and optimization activity.
Oil and gas production and marketing revenue increased to $253.7 million in
2002 compared to $111.6 million in 2001. The increase is due to a $175.0 million
increase in sales of purchased gas, offset by a $32.9 million decrease in oil
and gas sales to third parties primarily due to increased internal consumption.
Trading revenue, net -- Trading revenue, net decreased from $23.8 million
in 2001 to $(4.1) million in 2002. In the three months ended September 30, 2001,
we recognized significant mark-to-market gains from power contracts in a market
area where we did not have generation assets. Due to lower power prices and
industry-wide credit restrictions on risk management and trading activities in
2002, such opportunities and other trading activities have been greatly
restricted.
-31-
Cost of revenue -- Cost of revenue increased to $2,132.7 million in 2002
compared to $1,999.0 million in 2001. Approximately $167.9 million of the
increase relates to the cost of gas purchased by our energy services
organization due to increased price hedging, balancing and optimization
activities. Fuel expense increased 60%, from $327.9 million in 2001 to $525.5
million in 2002, due to an increase of 81% in gas-fired megawatt hours generated
as offset by slightly lower gas prices in 2002 and an improvement in average
heat rate of our generation portfolio. Plant operating expense increased by 51%
from $93.7 million to $141.3 million but, expressed per MWh of generation,
decreased from $6.85/MWh to $6.04/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 47%, from $80.0 million to $117.6 million,
due primarily to additional power facilities in consolidated operations at
September 30, 2002, as compared to the same period in 2001. These increases were
somewhat offset by a $335.0 million decrease in purchased power expense that was
caused by lower power prices and by industry-wide credit restrictions on risk
management activities in 2002, which has resulted in a lower volume of hedging
and optimization activity.
Project development expense -- Project development expense increased $19.0
million as we expensed approximately $7.7 million in costs related to the
cancellation or indefinite suspension of certain development projects.
General and administrative expense -- General and administrative expense
increased to $57.3 million during the third quarter 2002 as compared to $29.4
million in the prior year. The increase is due to the growth of our
infrastructure needed to support operations, whose output has grown by
approximately 87% and due to severance costs relating to reduction of excess
staffing. In the comparable period of 2001, we revised our estimate of bonus
expense to reflect a higher mix of stock options versus cash in compensation.
Interest expense -- Interest expense increased 139% to $113.8 million for
the three months ended September 30, 2002, from $47.7 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 fourth
quarter 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 were in commercial operation in the
three months ended September 30, 2002, than in the three months ended September
30, 2001. Interest capitalized in 2002 and 2001 was $123.2 million and $121.6
million, respectively. 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, to a lesser extent, as a result of
suspension of certain of our development projects.
Interest income -- Interest income decreased to $10.8 million for the three
months ended September 30, 2002, compared to $21.1 million for the same period
in 2001. This decrease is due primarily to lower cash balances and interest
rates in 2002.
Other -- Other income increased by $25.9 million in the three months ended
September 30, 2002, compared to the same period in 2001. In the 2002 period we
recognized $38.6 million from the termination of a power sales agreement and
$2.9 million in Canadian foreign exchange gains. These were partially offset by
$4.7 million of letter of credit fees and a $3.0 million loss on the sale of two
turbines.
Provision for income taxes -- The provision for income taxes as a percent
of income before provision for income taxes decreased from approximately 31% to
25% for the three months ended September 30, 2002 and 2001, respectively. The
decrease in rates was due to our expansion into Canada and the United Kingdom,
our cross border financings in October 2001, our revision of estimated year end
earnings for 2002, and our revision of tax accruals.
Discontinued operations, net of tax -- Discontinued operations, net of tax
for the three months ended September 30, 2002, was $17.0 million as compared to
$7.3 million in 2001. The 2002 amount includes a $12.9 million after-tax gain on
the sale of certain oil and gas properties. See Note 7 to the Condensed
Consolidated Financial Statements for further discussion.
Nine Months Ended September 30, 2002, Compared to Nine Months Ended September
30, 2001.
Revenue -- Total revenue increased to $5,586.7 million for the nine months
ended September 30, 2002, compared to $5,304.8 million for the same period in
2001.
Electric generation and marketing revenue increased by $311.0 million to
$4,796.4 million in 2002 compared to $4,485.4 million in 2001. Sales of
purchased power decreased by $153.9 million due to lower power prices and
industry-wide credit restrictions on risk management activities in 2002, which
has resulted in a lower volume of hedging and optimization activity. Electricity
and steam sales increased by $465.0 million due to our growing portfolio of
power plants. Generation increased 87%, but average pricing dropped to moderate
-32-
revenue growth. Our revenue for the period ended September 30, 2002, includes
the consolidated results of additional facilities that we completed construction
on subsequent to September 30, 2001.
Oil and gas production and marketing revenue increased to $755.7 million in
2002 compared to $652.7 million in 2001. The increase is primarily due to a
$253.3 million increase in the sales of purchased gas offset by a $150.4 million
decrease in oil and gas sales to third parties because of much lower average
natural gas pricing in 2002 and increased internal consumption.
Trading revenue, net -- Trading revenue, net decreased from $129.2 million
in 2001 to $9.3 million in 2002. In the nine months ended September 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 lower power prices and
industry-wide credit restrictions on risk management and trading activities in
2002, such opportunities and other trading activities have been greatly
restricted.
Cost of revenue -- Cost of revenue increased to $4,809.4 million in 2002
compared to $4,256.7 million in 2001. Approximately $288.4 million of the $552.7
million increase relates to the cost of gas purchased by our energy services
organization due to increased price hedging, balancing and optimization
activities. Fuel expense increased 43%, from $846.2 million in 2001 to $1,208.1
million in 2002, due to a 104% increase in gas-fired megawatt hours generated as
offset by significantly lower gas prices, increased usage of internally produced
gas and an improved average heat rate of our generation portfolio in 2002. Plant
operating expense increased by 52% from $246.0 million to $374.5 million but,
expressed per MWh of generation, decreased from $8.54/MWh to $6.96/MWh as
economies of scale are being realized due to the increase in the average size of
our plants. Royalty expense decreased $10.1 million between periods due to a
decrease in revenue for The Geysers geothermal plants. Depreciation, depletion
and amortization expense increased by 56%, from $199.5 million to $310.9
million, due primarily to additional power facilities in consolidated operations
at September 30, 2002, as compared to the same period in 2001. Operating lease
expense increased 31% due to sale/leaseback transactions subsequent to September
30, 2001.
Project development expense -- Project development expense increased 139%
from $25.1 million for the nine months ended September 30, 2001, as compared to
$60.0 million for the same period in 2002, as we expensed $28.0 million in costs
related to the cancellation or indefinite suspension of certain development
projects.
Equipment cancellation cost -- The pre-tax equipment cancellation charge of
$172.2 million in the nine months ended September 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 48% to $170.4 million for the nine months ended September 30, 2002, as
compared to $114.9 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, in addition to
severance costs from the reduction of our work force. General and administrative
expense expressed per KWh of generation decreased to $3.17/KWh in 2002 from
$3.99/KWh in 2001.
Merger expense -- The merger expense of $41.6 million in the nine months
ended September 30, 2001 was a result of the pooling-of-interests transaction
with Encal Energy Ltd. that closed on April 19, 2001.
Interest expense -- Interest expense increased 122% to $239.1 million for
the nine months ended September 30, 2002, from $107.5 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 new plants going into commercial operations at which
point capitalization of interest expense ceases. Interest capitalized increased
from $341.2 million in the nine months ended September 30, 2001 to $457.3
million in the nine months ended September 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, to a lesser extent, as a
result of suspension of certain of our development projects.
Interest income -- Interest income decreased to $34.0 million for the nine
months ended September 30, 2002, compared to $60.9 million for the same period
in 2001. This decrease is due primarily to lower cash balances and interest
rates in 2002.
Other (income) expense -- Other income increased by $34.0 million in the
nine months ended September 30, 2002, compared to the same period in 2001,
primarily due to a $38.6 million gain we recognized on the termination of a
power sales agreement.
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Provision for income taxes -- The provision for income taxes as a percent
of income before provision for income taxes decreased from approximately 35% to
23% for the nine months ended September 30, 2002 and 2001, respectively. The
decrease in rates was due to our expansion into Canada and the United Kingdom,
our cross border financings in April 2001 and October 2001, our revision of
estimated year end earnings for 2002, and our revision of tax accruals.
Discontinued operations, net of tax -- Discontinued operations, net of tax
was $27.0 million and $36.3 million for the nine months ending September 30,
2002 and 2001, respectively. The decrease in 2002 results, despite a $12.9
million gain on sale of oil and gas properties, reflects substantially higher
gas prices in 2001. See Note 7 to the Consolidated Condensed Financial
Statements for further discussion.
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."
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 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.
Accumulated other comprehensive loss -- The amount of the accumulated other
comprehensive loss increased from $(226.6) million at December 31, 2001, to
$(230.3) million at September 30, 2002. The change resulted from unrealized
losses on derivatives designated as cash flow hedges of $(19.8) million, net of
amounts reclassified to net loss and income taxes, and foreign currency
translation gain of $16.1 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 Corp. and a perceived
near term surplus supply of electric generating capacity. While we were 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 and due to current market
conditions, 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 demand increases and attractive financing
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 certain 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,
repay debt, 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 or use it to repay debt, 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.
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Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Nine Months Ended September 30,
-------------------------------
2002 2001
------------ ------------
(in thousands)
Beginning cash and cash equivalents........................................... $ 1,525,417 $ 596,077
Net cash provided by (used in):
Operating activities....................................................... 785,015 476,005
Investing activities....................................................... (3,197,790) (6,085,999)
Financing activities....................................................... 1,544,775 5,490,291
Effect of exchange rates changes on cash and cash equivalents.............. 2,277 --
------------ ------------
Net increase (decrease) in cash and cash equivalents....................... (865,723) (119,703)
------------ ------------
Ending cash and cash equivalents........................................ $ 659,694 $ 476,374
============ ============
Operating activities for the nine months ended September 30, 2002, provided
net cash of $785.0 million, compared to $476.0 million for the nine months ended
September 30, 2001. The cash provided by operating activities for the nine
months ended September 30, 2002, consisted of a $420.2 million decrease in
operating assets, primarily relating to a $472.1 million decrease in accounts
receivable, and current derivative assets and other current assets. This was
offset by a $494.4 million decrease in operating liabilities, primarily related
to derivative activity. A primary factor causing the significant increase in
cash flow from operations in the nine months ended September 30, 2002, in
comparison to the same period in 2001, is the realization of approximately
$222.3 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 nine months of 2001, which
reduced operating cash flow in that period.
Investing activities for the nine months ended September 30, 2002, consumed
net cash of $3.2 billion, primarily due to construction costs and capital
expenditures including gas turbine generator costs and associated capitalized
interest, $64.7 million of advances to joint ventures including associated
capitalized interest for investments in power projects under construction, $84.8
million of capitalized project development costs including associated
capitalized interest, and a $14.5 million increase in restricted cash. This was
partially offset by $125.1 million of proceeds from sales of physical assets.
Financing activities for the nine months ended September 30, 2002, provided
$1.5 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, $1.3 billion of proceeds from drawings on
our term loan and revolving lines of credit, $169.4 million of proceeds from our
Canadian Income Trust Offering, and $438.5 million of proceeds from project
financing. This was partially offset by $869.7 million for the repurchase of the
outstanding Zero Coupons, $75.7 million for the repayment of notes payable and
borrowings under our lines of credit, $153.8 million for repayments of project
financing, and additional financing costs.
We continue to evaluate current and forecasted cash flow as a basis for
funding operating requirements and capital expenditures. In November 2003 and
2004 the Company's $1.0 billion and $2.5 billion secured revolving construction
financing facilities will mature, requiring the Company to refinance this
indebtedness. At September 30, 2002, there was $969.8 million and $2,493.6
million outstanding, respectively, under these facilities. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under lines of credit, access to sale/leaseback and other markets,
sale of certain assets and cash balances to satisfy all obligations under
outstanding indebtedness, and to fund anticipated capital expenditures and
working capital requirements for the next twelve months.
Enron Bankruptcy-- During 2001 we, primarily through our 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.
-35-
We have conducted no business with EPMI or ENA since December 31, 2001. We
have terminated all of our 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.
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).
Management believes, based on contractually permissible calculation
methodologies, that our gross exposure to Enron and its affiliates will be
significantly less than amounts previously disclosed using calculations made
under generally accepted accounting principles. We expect that this amount will
be offset by CES' losses, damages, attorneys' fees and other expenses arising
from the default by Enron.
We are engaged in confidential settlement negotiations with Enron, ENA and
EPMI. It is premature to characterize these negotiations at this time. In the
event settlement negotiations prove unsuccessful, we intend to pursue our rights
under our agreements with Enron and its affiliates. Regardless of the outcome,
we believe, based upon legal analysis, that we do not have any net collection
exposure to Enron and its affiliates as at the date hereof.
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
requested that its power suppliers extend payment terms to help it overcome its
short-term liquidity problems. In June and July 2002 NPC underpaid us by
approximately $4.2 million, and we established a bed debt reserve of
approximately $2.7 million against NPC receivables. On October 25, 2002, we
received approximately $22.2 million from NPC for outstanding payables owed to
us for power deliveries made during the period of May 1, 2002 through September
15, 2002. See Part II -- Other Information - Item 1 for further discussion.
As of September 30, 2002, we had net collection exposures of approximately
$35.1 million and $9.6 million with NPC and SPPC, respectively. 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.
NRG Power Marketing, Inc.-- We have open contract positions with NRG Power
Marketing, Inc., a subsidiary of NRG Energy, Inc., which in turn is the
unregulated power-generation subsidiary of XCEL Energy Inc. Almost all of the
open contracts are accounted for as cash flow hedges under Financial Accounting
Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS")
No. 133, "Accounting for Derivative Instruments and Hedging Activities." NRG
Energy, Inc. has reportedly experienced financial problems, defaulted on certain
loan payments and has had its long-term debt rating downgraded to D by Standard
& Poor's. According to a report published on November 8, 2002, NRG Energy, Inc.
has discussed a Chapter 11 bankruptcy filing with its lenders. While NRG Power
Marketing, Inc. has remained current in its payments to us through October 20,
2002, we have established a partial reserve in other comprehensive income
("OCI") in the balance sheet against the fair value of our open contract
position with NRG Power Marketing, Inc. Our exposure to NRG Power Marketing,
Inc. at September 30, 2002, is approximately $8.8 million, net of established
reserve. We will continue to closely monitor our position with NRG Power
Marketing, Inc. and will adjust the value of the reserve as conditions dictate.
PSM License Receivable -- In December 2001 our wholly owned subsidiary,
Power Systems Mfg., LLC ("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. We 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 $6
million, with no payments 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 has also filed 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, we have not
established a reserve against the related receivable but will continue to
closely monitor the situation.
-36-
CES Margin Deposits and Other Credit Support -- As of September 30, 2002,
CES had $49.8 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 $181.6 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. Fifteen of
these facilities have subsequently achieved full or partial commercial operation
as of September 30, 2002. Construction of advanced stage development projects is
expected to proceed only when there is an established market need for additional
generating resources at prices that will allow us to meet our 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 $172.2 million in the first nine months of 2002.
Capital Availability -- As a result of the significant contraction in the
availability of capital for participants in the energy sector, access to capital
for many in the sector, including the Company, has been restricted. While we
were able earlier in the year to access the capital and bank credit markets, the
terms of financing available to us now and in the future may not be attractive
to us and the timing of the availability of capital is uncertain and is
dependent, in part, on market conditions that are difficult to predict and are
outside of our control. 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. $50.0 million was repaid on August 7, 2002, and the remaining
$50.0 million (which is classified as current project financing) is payable on
November 25, 2002.
On May 31, 2002, we increased our two-year secured bank term loan to $1.0
billion from $600 million, and reduced the aggregate size of our secured
corporate revolving credit facilities to $1.0 billion (the $600 million and $400
million facilities, respectively,) from $1.4 billion. At September 30, 2002, we
had $1.0 billion in funded borrowings outstanding under the term loan facility
and $250.0 million in funded borrowings outstanding under the revolving credit
facilities. Subsequently, $50.4 million of the proceeds of the sale of our
British Columbia oil and gas properties to Pengrowth Corporation was applied to
repay a portion of the term loan facility.
Letter of credit facilities -- At September 30, 2002, we had approximately
$697.0 million in letters of credit outstanding under various credit facilities
to support CES risk management, and other operational and construction
activities. Of the total letters of credit outstanding, $595.2 million were
issued under the corporate revolving credit facilities. At December 31, 2001, we
had $642.5 million in letters of credit outstanding to support CES risk
management, and other operational and construction 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 entered into sale/leaseback transactions involving our
Tiverton and Rumford projects in December 2000 and our South Point, Broad River
and RockGen projects in October 2001. 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.
In accordance with Accounting Principles Board ("APB") Opinion No. 18 "The
Equity Method of Accounting For Investments in Common Stock" and FASB
Interpretation No. 35, "Criteria for Applying the Equity Method of Accounting
for Investments in Common Stock (An Interpretation of APB Opinion No. 18)," the
debt on the books of our unconsolidated investments in power projects is not
-37-
reflected on our balance sheet. At September 30, 2002, investee debt totaled
$652.1 million. Based on our pro rata ownership share of each of the
investments, our share would be $242.8 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, provided support arrangements
until construction was completed to cover cost overruns, if any.
Performance Metrics
In understanding our business, we believe that certain performance metrics
are particularly important. These include:
o Average gross profit margin based on non-GAAP revenue and non-GAAP
cost of revenue. A high percentage of our recent revenue has consisted
of CES hedging, balancing and optimization 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 and
optimization 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 for hedging, balancing and
optimization activities 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. However, effective July 1, 2002, trading activity is now
shown net in our Statements of Operations under Trading revenue, net
for all periods presented. Because of the inflating effect on revenue
of much of our hedging, balancing and optimization activity, we
believe that revenue levels and trends do not reflect our performance
as accurately as gross profit, and that it is analytically useful for
investors to look at our results on a non-GAAP basis with all hedging,
balancing and optimization activity netted. This analytical approach
nets the sales of purchased power with purchased power expense and
includes that net amount as an adjustment to E&S revenue for our
generation assets. Similarly, we believe that it is analytically
useful for investors to net the sales of purchased gas with purchased
gas expense and include that net amount as an adjustment to fuel
expense. This allows us to look at all hedging, balancing and
optimization 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 GAAP revenue of hedging, balancing and
optimization 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 the product of multiplying (b) the weighted
average megawatts in operation during the period by (c) the total
hours in the period. The capacity factor is thus a measure of total
actual generation as a percent of total potential generation. If we
elect not to generate during periods when electricity pricing is too
low or gas prices too high to operate profitably, the 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.
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.
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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
fuel expense 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 fuel expense from
(b) adjusted E&S revenue and dividing the difference by (c) total
generated MWh in the period.
The table below presents, side-by-side, both our GAAP and non-GAAP netted
revenue, costs of revenue and gross profit showing the purchases and sales of
electricity and gas for hedging, balancing and optimization activity on a net
basis. It also shows the other performance metrics discussed above.
Non-GAAP Netted
GAAP Presentation Presentation
Three Months Ended September 30, Three Months Ended September 30,
-------------------------------- --------------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Revenue, Cost of Revenue and Gross Profit
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue(2)....................... $ 947,326 $ 710,506 $ 1,170,462 $ 968,723
Sales of purchased power for hedging and
optimization (2)...................................... 1,282,976 1,653,088 -- --
----------- ----------- ----------- -----------
Total electric generation and marketing revenue...... 2,230,302 2,363,594 1,170,462 968,723
Oil and gas production and marketing revenue
Oil and gas sales...................................... 21,827 54,693 21,827 54,693
Sales of purchased gas for hedging and
optimization (2)...................................... 231,893 56,916 -- --
----------- ----------- ----------- -----------
Total oil and gas production and marketing revenue... 253,720 111,609 21,827 54,693
Trading revenue, net
Realized revenue on power and gas trading
transactions, net..................................... 6,845 16,700 6,845 16,700
Unrealized mark-to-market gain (loss) on power
and gas transactions, net............................. (10,957) 7,128 (10,957) 7,128
----------- ----------- ----------- -----------
Total trading revenue, net........................... (4,112) 23,828 (4,112) 23,828
Income (loss) from unconsolidated investments in
power projects........................................... 10,176 6,859 10,176 6,859
Other revenue............................................. 4,924 14,261 4,924 14,261
----------- ----------- ----------- -----------
Total revenue..................................... 2,495,010 2,520,151 1,203,277 1,068,364
----------- ----------- ----------- -----------
(continues next page)
-39-
Non-GAAP Netted
GAAP Presentation Presentation
Three Months Ended September 30, Three Months Ended September 30,
-------------------------------- --------------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Cost of revenue:
Electric generation and marketing expense
Plant operating expense................................ 141,262 93,709 141,262 93,709
Royalty expense........................................ 4,743 5,255 4,743 5,255
Purchased power expense for hedging and
optimization (2)...................................... 1,059,840 1,394,871 -- --
----------- ----------- ----------- -----------
Total electric generation and marketing expense...... 1,205,845 1,493,835 146,005 98,964
Oil and gas production and marketing expense
Oil and gas production expense......................... 22,953 13,009 22,953 13,009
Purchased gas expense for hedging and
optimization (2)...................................... 220,775 52,856 -- --
----------- ----------- ----------- -----------
Total oil and gas production and marketing expense... 243,728 65,865 22,953 13,009
Fuel expense.............................................. 525,478 327,947 514,360 323,887
Depreciation, depletion and amortization expense.......... 117,568 80,044 117,568 80,044
Operating lease expense................................... 36,520 27,830 36,520 27,830
Other expense............................................. 3,539 3,485 3,539 3,485
----------- ----------- ----------- -----------
Total cost of revenue............................. 2,132,678 1,999,006 840,945 547,219
----------- ----------- ----------- -----------
Gross profit................................................. $ 362,332 $ 521,145 $ 362,332 $ 521,145
=========== =========== =========== ===========
Gross profit margin.......................................... 15% 21% 30% 49%
Non-GAAP Netted
GAAP Presentation Presentation
Nine Months Ended September 30, Nine Months Ended September 30,
-------------------------------- --------------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Revenue, Cost of Revenue and Gross Profit
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue(2)....................... $ 2,269,892 $ 1,804,889 $ 2,756,493 $ 2,088,573
Sales of purchased power for hedging and
optimization (2)...................................... 2,526,555 2,680,488 -- --
----------- ----------- ----------- -----------
Total electric generation and marketing revenue...... 4,796,447 4,485,377 2,756,493 2,088,573
Oil and gas production and marketing revenue
Oil and gas sales...................................... 89,585 239,940 89,585 239,940
Sales of purchased gas for hedging and
optimization (2)...................................... 666,095 412,782 -- --
----------- ----------- ----------- -----------
Total oil and gas production and marketing revenue... 755,680 652,722 89,585 239,940
Trading revenue, net
Realized revenue on power and gas trading
transactions, net..................................... 15,276 21,340 15,276 21,340
Unrealized mark-to-market gain (loss) on power
and gas transactions, net............................. (5,952) 107,862 (5,952) 107,862
----------- ----------- ----------- -----------
Total trading revenue, net 9,324 129,202 9,324 129,202
Income from unconsolidated investments in
power projects........................................... 10,499 9,021 10,499 9,021
Other revenue............................................. 14,792 28,444 14,792 28,444
----------- ----------- ----------- -----------
Total revenue..................................... 5,586,742 5,304,766 2,880,693 2,495,180
----------- ----------- ----------- -----------
(continues next page)
-40-
Non-GAAP Netted
GAAP Presentation Presentation
Nine Months Ended September 30, Nine Months Ended September 30,
-------------------------------- --------------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)
Cost of revenue:
Electric generation and marketing expense
Plant operating expense................................ 374,497 246,045 374,497 246,045
Royalty expense........................................ 13,092 23,181 13,092 23,181
Purchased power expense for hedging and
optimization (2)...................................... 2,039,954 2,396,804 -- --
----------- ----------- ----------- -----------
Total electric generation and marketing expense...... 2,427,543 2,666,030 387,589 269,226
Oil and gas production and marketing expense
Oil and gas production expense......................... 67,381 62,371 67,381 62,371
Purchased gas expense for hedging and
optimization (2)...................................... 678,192 389,814 -- --
----------- ----------- ----------- -----------
Total oil and gas production and marketing expense... 745,573 452,185 67,381 62,371
Fuel expense............................................... 1,208,092 846,195 1,220,189 823,227
Depreciation, depletion and amortization expense.......... 310,943 199,509 310,943 199,509
Operating lease expense................................... 108,917 83,289 108,917 83,289
Other expense............................................. 8,333 9,474 8,333 9,474
----------- ----------- ----------- -----------
Total cost of revenue............................. 4,809,401 4,256,682 2,103,352 1,447,096
----------- ----------- ----------- -----------
Gross profit................................................. $ 777,341 $ 1,048,084 $ 777,341 $ 1,048,084
=========== =========== =========== ===========
Gross profit margin.......................................... 14% 20% 27% 42%
Non-GAAP Netted Non-GAAP Netted
Presentation Presentation
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2002 2001 2002 2001
---------- ----------- ----------- -----------
(In thousands)
Other Non-GAAP Performance Metrics
Average availability and capacity factor:
Average availability...................................... 94% 96% 92% 93%
Average capacity factor or operating rate based on
total hours (excluding peakers).......................... 73% 76% 70% 71%
Average heat rate for gas-fired power plants (excluding
peakers) (Btu's/kWh):
Not steam adjusted........................................ 7,646 8,069 7,937 8,329
Steam adjusted............................................ 7,078 7,415 7,268 7,490
Average all-in realized electric price:
Adjusted electricity and steam revenue
before discontinued operations (in thousands)............ $ 1,170,462 $ 968,723 $ 2,756,493 $ 2,088,573
Electricity and steam revenue from discontinued
operations............................................... 4,440 4,463 10,091 10,936
Adjusted electricity and steam revenue.................... 1,174,902 973,186 2,766,584 2,099,509
MWh generated (in thousands).............................. 23,375 13,687 53,809 28,804
Average all-in realized electric price per MWh............ $ 50.26 $ 71.10 $ 51.41 $ 72.89
Average cost of natural gas:
Fuel expense.............................................. $ 514,360 $ 323,887 $ 1,220,189 $ 823,227
Fuel cost elimination..................................... 46,957 9,784 116,911 88,455
Fuel expense from discontinued operations................. 2,418 2,489 4,551 5,564
----------- ----------- ----------- -----------
Adjusted fuel expense..................................... $ 563,735 $ 336,160 $ 1,341,651 $ 917,246
MMBtu of fuel consumed by generating plants
(in thousands)........................................... 158,420 92,695 377,694 193,838
Average cost of natural gas per MMBtu..................... $ 3.56 $ 3.63 $ 3.55 $ 4.73
MWh generated (in thousands).............................. 23,375 13,687 53,809 28,804
Average cost of oil and natural gas burned by
power plants per MWh..................................... $ 24.12 $ 24.56 $ 24.93 $ 31.84
Average spark spread:
Adjusted electricity and steam revenue (in thousands)..... $ 1,174,902 $ 973,186 $ 2,766,584 $ 2,099,509
Less: Adjusted fuel expense (in thousands)............. 563,735 336,160 1,341,651 917,246
----------- ----------- ----------- -----------
Spark spread (in thousands)............................... $ 611,167 $ 637,026 $ 1,424,933 $ 1,182,263
MWh generated (in thousands).............................. 23,375 13,687 53,809 28,804
Average spark spread per MWh.............................. $ 26.14 $ 46.54 $ 26.48 $ 41.05
-41-
For the three and nine months ended September 30, 2002 and 2001, trading
revenue, net consisted of (dollars in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2002 2001 2002 2001
--------- --------- --------- --------
ELECTRICITY
Realized gain (loss) Realized revenue on power trading transactions, net.. $ 2,329 $ 4,309 $ 3,305 $ 4,066
Unrealized mark-to-market gain (loss) on power
Unrealized transactions, net................................... (1,068) 13,577 9,201 83,316
-------- -------- -------- --------
Subtotal................................................................. $ 1,261 $ 17,886 $ 12,506 $ 87,382
GAS
Realized gain (loss) Realized revenue on gas trading transactions, net.... $ 4,516 $ 12,391 $ 11,971 $ 17,274
Unrealized mark-to-market gain (loss) on gas
Unrealized transactions, net................................... (9,889) (6,449) (15,153) 24,546
-------- -------- -------- --------
Subtotal................................................................. $ (5,373) $ 5,942 $ (3,182) $ 41,820
Three Months Three Months
Ended Percent of Ended Percent of
September 30, Gross September 30, Gross
2002 Profit 2001 Profit
------------- --------- ------------- ----------
Total trading activity gain (loss)....................................... $ (4,112) (1.1)% $ 23,828 4.6%
Realized gain............................................................ $ 6,845 1.9% $ 16,700 3.2%
Unrealized (mark-to-market) gain (loss)(1)............................... $ (10,957) (3.0)% $ 7,128 1.4%
Nine Months Nine Months
Ended Percent of Ended Percent of
September 30, Gross September 30, Gross
2002 Profit 2001 Profit
------------- --------- ------------- ----------
Total trading activity gain.............................................. $ 9,324 1.2% $ 129,202 12.3%
Realized gain............................................................ $ 15,276 2.0% $ 21,340 2.0%
Unrealized (mark-to-market) gain (loss)(1)............................... $ (5,952) (0.8)% $ 107,862 10.3%
(1) For the three and nine months ended September 30, 2002, the mark-to-market
gains shown above as "trading" activity include a net loss on hedge
ineffectiveness of $(5,213) and $(3,712), consisting of an ineffectiveness
loss on power hedges of $(3,072) and $(4,296) and an ineffectiveness gain
(loss) on gas hedges of $(2,141) and $584. For the three and nine months
ended September 30, 2001, the mark-to-market gains shown above as "trading"
activity include a net loss on hedge ineffectiveness of $(2,346) and
$(5,818), consisting of an ineffectiveness gain on power hedges of $0 and
$0, and an ineffectiveness loss on gas hedges of $(2,346) and $(5,818).
(2) Following is a reconciliation of GAAP to non-GAAP presentation further to
the narrative set forth under this Performance Metrics section ($ in
thousands):
-42-
Total Net
Hedging,
Balancing & Netted
GAAP Optimization Non-GAAP
Balance Activity Balance
----------- ------------- -----------
Three months ended September 30, 2002
Electricity and steam revenue................................ $ 947,326 $ 223,136 $ 1,170,462
Sales of purchased power for hedging and optimization........ 1,282,976 (1,282,976) --
Sales of purchased gas for hedging and optimization.......... 231,893 (231,893) --
Purchased power expense for hedging and optimization......... 1,059,840 (1,059,840) --
Purchased gas expense for hedging and optimization........... 220,775 (220,775) --
Fuel expense................................................. 525,478 (11,118) 514,360
Three months ended September 30, 2001
Electricity and steam revenue................................ $ 710,506 $ 258,217 $ 968,723
Sales of purchased power for hedging and optimization........ 1,653,088 (1,653,088) --
Sales of purchased gas for hedging and optimization.......... 56,916 (56,916) --
Purchased power expense for hedging and optimization......... 1,394,871 (1,394,871) --
Purchased gas expense for hedging and optimization........... 52,856 (52,856) --
Fuel expense................................................. 327,947 (4,060) 323,887
Total Net
Hedging,
Balancing & Netted
GAAP Optimization Non-GAAP
Balance Activity Balance
----------- ------------- -----------
Nine months ended September 30, 2002
Electricity and steam revenue................................ $ 2,269,892 $ 486,601 $ 2,756,493
Sales of purchased power for hedging and optimization........ 2,526,555 (2,526,555) --
Sales of purchased gas for hedging and optimization.......... 666,095 (666,095) --
Purchased power expense for hedging and optimization......... 2,039,954 (2,039,954) --
Purchased gas expense for hedging and optimization........... 678,192 (678,192) --
Fuel expense................................................. 1,208,092 12,097 1,220,189
Nine months ended September 30, 2001
Electricity and steam revenue................................ $ 1,804,889 $ 283,684 $ 2,088,573
Sales of purchased power for hedging and optimization........ 2,680,488 (2,680,488) --
Sales of purchased gas for hedging and optimization.......... 412,782 (412,782) --
Purchased power expense for hedging and optimization......... 2,396,804 (2,396,804) --
Purchased gas expense for hedging and optimization........... 389,814 (389,814) --
Fuel expense................................................. 846,195 (22,968) 823,227
Overview
Summary of Key Activities
Power Plant Development and Construction:
Date Project Description
----- -------------------------------- -----------------------
7/02 Freestone Energy Center Commenced operations
7/02 Bethpage Power Plant Peaker Commenced operations
7/02 Oneta Energy Center Partial Commencement of
operations
8/02 Yuba City Energy Center Commenced Operations
8/02 Acadia Energy Center Commenced Operations
8/02 Hermiston Energy Center Commenced Operations
8/02 Auburndale Peaking Energy Center Commenced Operations
10/02 Corpus Christi Energy Center Commenced Operations
-43-
Finance
Note Repayments and New Funding:
Approximate
Date Amount Description
- ------- -------------------- ---------------------------------------
8/7/02 $50.0 million Repayment of peaker funding
8/22/02 $106.0 million Non-Recourse project financing for the
construction of the Blue Spruce
Energy Center
8/29/02 US$147.5 million, Canadian Power Income Fund
Cdn$230 million
8/29/02 US$81.0 million, Completed the sale of certain
Cdn$125.0 million non-strategic oil and gas properties
("Medicine River properties") located
in central Alberta to NAL Oil and Gas
Trust and another institutional
investor
9/20/02 US$21.9 million, Canadian Power Income Fund
Cdn$34.5 million
10/1/02 US$243.7 million, Sale of substantially all of our British
Cdn$387.5 million Columbia oil and gas properties to
Calgary, Alberta-based Pengrowth
Corporation
Other:
Date Description
- -------- --------------------------------------------------------------
9/16/02 Received regulatory approval for the sale of the DePere Energy
Center
9/30/02 Renegotiation of a 10-year power sales agreement with the City
of Lodi
10/25/02 Received approximately $22.2 million from Las Vegas-based
Nevada Power Company
10/31/02 Received approximately $3 million from Goldking Energy
Corporation for all of the oil and gas properties in Drake
Bay Field
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 without
admitting any liability on the part of the Company.
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. Based on the terms of the DWR contracts, we expect to 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
-44-
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.
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. In addition, as
discussed above, due to industry-wide credit restrictions, our hedging,
balancing and optimization activities have been reduced and may be further
reduced in the future.
The change in fair value of outstanding commodity derivative instruments
from January 1, 2002, through September 30, 2002, is summarized in the table
below (in thousands):
Fair value of contracts outstanding at January 1, 2002.......................................... $ (88,123)
Gains recognized or otherwise settled during the period (1).................................. (149,536)
Changes in fair value attributable to changes in valuation techniques and assumptions........ --
Change in fair value attributable to new contracts and price movements (2)................... 159,769
Terminated derivatives (2)................................................................... 239,573
---------
Fair value of contracts outstanding at September 30, 2002 (3)............................. $ 161,683
=========
- ----------
(1) Recognized gains from commodity cash flow hedges of $134.3 million
reported in Note 8 of the financial statements and $15.3 million realized
gain on trading activity reported in the Statement of Operations under
trading revenue, net.
(2) Includes the value of derivatives settled before their scheduled maturity
and the value of commodity financial instruments that ceased to qualify as
derivative instruments.
(3) Net commodity derivative 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 September
30, 2002, based on price source and the period during which the instruments will
mature are summarized in the table below (in thousands):
Fair Value Source 2002 2003-2004 2005-2006 After 2006 Total
- ----------------- ---------- --------- ---------- ---------- ----------
Prices actively quoted................................ $ 2,779 $ 102,030 $ -- $ -- $ 104,809
Prices provided by other external sources............. 16,087 31,777 37,252 -- 85,116
Prices based on models and other valuation methods.... (276) 3,220 (24,713) (6,473) (28,242)
---------- ---------- ---------- --------- ----------
Total fair value................................... $ 18,590 $ 137,027 $ 12,539 $ (6,473) $ 161,683
========== ========== ========== ========= ==========
-45-
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 September 30, 2002, and the
period during which the instruments will mature are summarized in the table
below (in thousands):
Credit Quality (based on October 16, 2002, ratings) 2002 2003-2004 2005-2006 After 2006 Total
- --------------------------------------------------- --------- --------- --------- ---------- ----------
Investment grade ..................................... $ (7,671) $ 129,826 $ 14,386 $ (11,089) $ 125,452
Non-investment grade ................................. 26,031 7,814 (1,750) 4,660 36,755
No external ratings .................................. 230 (613) (97) (44) (524)
--------- --------- --------- --------- ----------
Total fair value .................................. $ 18,590 $ 137,027 $ 12,539 $ (6,473) $ 161,683
========= ========= ========= ========= ==========
The fair value of outstanding derivative commodity instruments and the fair
value that would be expected after a ten percent adverse price change are shown
in the table below (in thousands):
Fair
Value After
10% Adverse
Fair Value Price Change
---------- ------------
At September 30, 2002:
Crude oil.............................. $ (4,664) $ (9,063)
Electricity............................ 162,086 73,536
Natural gas............................ 4,261 (120,464)
---------- ----------
Total............................... $ 161,683 $ (55,991)
========== ==========
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 fair
value of electricity derivative commodity instruments after a 10% adverse price
change includes the effect of increased power prices versus our derivative
forward commitments. Conversely, the fair value of the natural gas derivatives
after a 10% adverse price change reflects a general decline in gas prices versus
our derivative forward commitments. Derivative commodity instruments offset
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 65%
from December 31, 2001, to September 30, 2002, while the total volume of open
power derivative positions decreased 17% 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 OCI, net of tax, or in the statement of operations as an item (gain or
loss) of current earnings. As of September 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 nine months ended September 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
-46-
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:
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.
Collateral Debt Securities - The King City operating lease commitment is
supported by collateral debt securities that mature serially in amounts equal to
a portion of the semi-annual lease payment. We have the ability and intent to
hold these securities to maturity, and as a result, we do not expect a sudden
change in market interest rates to have a material affect on the value of the
securities at the maturity date. The securities are recorded at an amortized
cost of $85.0 million at September 30, 2002. The following tables present our
different classes of collateral debt securities by expected maturity date and
fair market value as of September 30, 2002, (dollars in thousands):
Expected Maturity Date
-------------------------------------------------------------
Weighted
Average
Interest
Rate 2003 2004 2005 2006 Thereafter Total
-------- -------- -------- -------- -------- ---------- --------
Corporate Debt Securities .............. 7.2% $ 2,015 $ 6,050 $ 7,825 $ -- $ -- $ 15,890
Government Agency Debt
Securities ............................ 6.9% 1,960 -- -- -- -- 1,960
U.S. Treasury Notes .................... 6.5% -- -- 1,975 -- -- 1,975
U.S. Treasury Securities
(non-interest bearing) ................ -- 4,065 -- -- 9,700 105,250 119,015
-------- -------- -------- -------- -------- --------
Total ............................... $ 8,040 $ 6,050 $ 9,800 $ 9,700 $105,250 $138,840
======== ======== ======== ======== ======== ========
Fair Market Value
-----------------
Corporate Debt Securities........... $ 16,892
Government Agency Debt Securities... 1,994
U.S. Treasury Notes................. 2,223
U.S. Treasury Securities
(non-interest bearing)............. 83,387
--------
Total............................ $104,496
========
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 September 30,
2002, (dollars in thousands):
Weighted Average Weighted Average
Notional Principal Interest Rate Interest Rate Fair Market
Maturity Date Amount (Pay) (Receive) Value
------------- ------------------ ---------------- ---------------- -----------
2008............ $ 44,250 4.2% (1) $ (4,681)
2011............ 51,760 6.9% 3-month US LIBOR (7,838)
2012............ 117,936 6.5% 3-month US LIBOR (19,416)
2014............ 67,929 6.7% 3-month US LIBOR (10,432)
---------- ---------
Total........ $ 281,875 6.3% $ (42,367)
========== =========
- ----------
(1) 1-month US LIBOR until July, 2003. 3-month US LIBOR thereafter.
-47-
Frequency of
Currency Fair Market
Maturity Date Notional Principal Fixed Currency Exchange Exchange Value
- ------------- ----------------------------------- ------------------------------- ------------ -----
(Pay/Receive) (Pay/Receive)
2007........... US$127,763/Cdn$200,000 US$5,545/Cdn$8,750 Semi-annually $ (9,176)
2008........... Pound sterling 109,550/Euro 175,000 Pound sterling 5,152/Euro 7,328 Semi-annually (4,461)
---------
Total....... $ (13,637)
=========
Debt financing -- Because of the significant capital requirements within
our industry, debt financing is often needed to fund our growth. We have used
three primary forms of debt: (1) long-term senior notes and related instruments,
including the Convertible Senior Notes Due 2006; (2) construction/project
financing; and (3) revolving credit and term loan agreements. 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 primarily 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. Our revolving credit and term loan facilities bear variable interest
rates and are used for general corporate purposes.
The following table summarizes the fair market value of our existing debt
financing as of September 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% $ 115,000
Senior Notes Due 2006......................................... 171,750 10.5% 85,875
Senior Notes Due 2006......................................... 250,000 7.6% 107,500
Convertible Senior Notes Due 2006............................. 1,200,000 4.0% 499,788
Senior Notes Due 2007......................................... 275,000 8.8% 115,500
Senior Notes Due 2007......................................... 126,120 8.8% 63,060
Senior Notes Due 2008......................................... 400,000 7.9% 156,000
Senior Notes Due 2008......................................... 2,030,000 8.5% 832,300
Senior Notes Due 2008......................................... 172,856 8.4% 58,771
Senior Notes Due 2009......................................... 350,000 7.8% 136,500
Senior Notes Due 2010......................................... 750,000 8.6% 300,000
Senior Notes Due 2011......................................... 2,000,000 8.5% 820,000
Senior Notes Due 2011......................................... 314,020 8.9% 103,627
------------ ------ ------------
Total long-term senior notes............................... $ 8,289,746 7.8% $ 3,393,921
============ ====== ============
Construction/project financing:
Blue Spruce Energy Center project financing................... $ 47,228 1-month US LIBOR $ 47,228
Term loan due (due 2004)...................................... 1,000,000 3-month US LIBOR 1,000,000
Calpine Construction Finance Company L.P. (due 2003).......... 969,771 1-month US LIBOR 969,771
Calpine Construction Finance Company II, LLC (due 2004)....... 2,493,596 1-month US LIBOR 2,493,596
------------ ---------------- ------------
Total long-term construction/project financing............. $ 4,510,595 $ 4,510,595
============ ============
Construction/project financing facilities -- In 2003 and 2004, $969.8
million and $2,493.6 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.
Revolving credit and term loan facilities -- On May 31, 2002, we increased
our two-year secured bank term loan to $1.0 billion from $600.0 million, and
reduced the aggregate size of our secured corporate revolving credit facilities
to $1.0 billion (the $600 million and $400 million facilities, respectively,)
from $1.4 billion. At September 30, 2002, we had $1.0 billion in funded
borrowings outstanding under the term loan facility, and $250.0 million in
funded borrowings outstanding, and $595.2 million in outstanding letters of
credit under the revolving credit facilities. The revolving credit facilities
expire in 2003. However, any letters of credit under the $600 million revolving
credit facility can be extended for one year at our option. In 2004 the $1
billion term loan matures.
-48-
New Accounting Pronouncements
In July 2001 we adopted SFAS No. 141, "Business Combinations," which
supersedes 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 our
consolidated financial statements.
On January 1, 2002, we 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.
We were 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. We 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. See Note 4 --
Goodwill and Other Intangible Assets, for further 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. We have not completed our
assessment of the impact of SFAS No. 143.
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 net effect on the
consolidated financial statements, although certain reclassifications have been
made to prior period financial statements to reflect the sale or designation as
"held for sale" of certain oil and gas and power plant assets and classification
of the operating results. In general gains from completed sales and any
anticipated losses on "held for sale" assts (of which there are none to date)
are included in discontinued operations net of tax. See Note 7 - Discontinued
Operations, for further information.
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. We have
elected early adoption of the provisions related to the rescission of SFAS No.
4, the effect of which has been reflected in these financial statements as
reclassifications of gains and losses from the extinguishment of debt from
extraordinary gain or loss to other (income) expense. The provisions related to
SFAS No. 13 shall be effective for transactions occurring 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 believe that the SFAS No. 145 provisions relating to
extinguishment of debt may have a material effect on future 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
-49-
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 EITF 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 other than timing of exit costs,
potentially.
In October 2002 the EITF discussed EITF Issue No. 02-3, "Issues Related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." The EITF reached a consensus to rescind EITF Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," the impact of which is to preclude mark-to-market accounting for
all energy trading contracts not within the scope of SFAS No. 133. The Task
Force also reached a consensus that gains and losses on derivative instruments
within the scope of SFAS No. 133 should be shown net in the income statement if
the derivative instruments are held for trading purposes. We expect that further
clarifications may be forthcoming from the EITF on this issue that could have an
affect on the presentation of our financial statements. We have not completed
our assessment of the impact that EITF No. 02-3 will have on our financial
statements. Effective July 1, 2002, we reclassified certain revenue and cost of
revenue to a net rather than gross basis in all periods presented in our
Statement of Operations.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in Item 2.
Item 4. Controls and Procedures.
The Company's senior management, including the Company's Chief Executive
Officer and Chief Financial Officer, evaluated the effectiveness of the
Company's disclosure controls and procedures within 90 days of the filing date
of this quarterly report. Based upon this evaluation, the Company's Chairman,
President and Chief Executive Officer along with the Company's Executive Vice
President and Chief Financial Officer concluded that the Company's disclosure
controls and procedures are effective in ensuring that material information
required to be disclosed is included in the reports that it files with the
Securities and Exchange Commission. There were no significant changes in the
Company's internal controls or, to the knowledge of the management of the
Company, in other factors that could significantly affect these controls
subsequent to the evaluation date. The certificates required by this item are
filed as a part of this Form 10-Q. See Certifications.
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.
-50-
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 as
defendants Calpine, certain of our officers and directors, and the underwriters
of the offering, 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 and its subsidiaries in each of
these lawsuits to be without merit, and we intend 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 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
-51-
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 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)
*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 Fourth Amendment to Second Amended and Restated Credit
Agreement, dated as of September 26, 2002, among the Company,
The Bank of Nova Scotia, as Administrative Agent, and the
Lenders named therein.
(continues next page)
-52-
EXHIBIT INDEX
(continued)
EXHIBIT
NUMBER DESCRIPTION
------- ---------------------------------------------------------------
+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 September 30, 2002:
Date of Report Date Filed Item Reported
--------------------------- ------------------ -------------
July 23, 2002............... July 24, 2002 Item 5,7
August 1, 2002.............. August 2, 2002 Item 5,7
August 9, 2002.............. August 12, 2002 Item 9
August 26, 2002............. August 27, 2002 Item 5,7
August 29, 2002............. August 30, 2002 Item 5,7
September 10, 2002.......... September 11, 2002 Item 5,7
September 19, 2002.......... September 20, 2002 Item 5,7
-53-
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: November 14, 2002 By: /s/ ROBERT D. KELLY
--------------------------------------
Robert D. Kelly
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: November 14, 2002 By: /s/ CHARLES B. CLARK, JR.
--------------------------------------
Charles B. Clark, Jr.
Senior Vice President and
Corporate Controller
(Principal Accounting Officer)
-54-
CERTIFICATIONS
Certificate of the Chairman, President and Chief Executive Officer
I, Peter Cartwright, the Chairman, President and Chief Executive Officer of
Calpine Corporation, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation
(the "registrant");
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/s/ Peter Cartwright
--------------------
Peter Cartwright
Chairman, President and
Chief Executive Officer
Calpine Corporation
-55-
Certificate of the Executive Vice President and Chief Financial Officer
I, Robert D. Kelly, the Executive Vice President and Chief Financial Officer of
Calpine Corporation, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation
(the "registrant");
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 14, 2002
/s/ Robert D. Kelly
-------------------
Robert D. Kelly
Executive Vice President and
Chief Financial Officer
Calpine Corporation
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The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- ---------------------------------------------------------------
*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation (a)
*3.2 Certificate of Correction of Calpine Corporation (b)
*3.3 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of Calpine Corporation (c)
*3.4 Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation (b)
*3.5 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (b)
*3.6 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (c)
*3.7 Certificate of Designation of Special Voting Preferred Stock of
Calpine Corporation (d)
*3.8 Certificate of Ownership and Merger Merging Calpine Natural Gas
GP, Inc. into Calpine Corporation (e)
*3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas
Company into Calpine Corporation (e)
*3.10 Amended and Restated By-laws of Calpine Corporation (f)
*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 Fourth Amendment to Second Amended and Restated Credit
Agreement, dated as of September 26, 2002, among the Company,
The Bank of Nova Scotia, as Administrative Agent, and the
Lenders named therein.
+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.
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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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