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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
Commission file number: 1-12079
Calpine Corporation
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes |X| No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes |X| No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
413,131,672 shares of Common Stock, par value $.001 per share, outstanding on
November 11, 2003
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CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2003
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Condensed Balance Sheets September 30, 2003 and December 31, 2002....................... 3
Consolidated Condensed Statements of Operations for the Three and Nine Months Ended
September 30, 2003 and 2002 (Restated)............................................................. 5
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended
September 30, 2003 and 2002 (Restated)............................................................. 7
Notes to Consolidated Condensed Financial Statements................................................. 9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 39
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................. 74
Item 4. Controls and Procedures................................................................................ 74
PART II - OTHER INFORMATION
Item 1. Legal Proceedings...................................................................................... 74
Item 6. Exhibits and Reports on Form 8-K....................................................................... 77
Signatures.......................................................................................................... 82
-2-
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
September 30, 2003 and December 31, 2002
(in thousands, except share and per share amounts)
September 30, December 31,
2003 2002
--------------- -------------
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents....................................................... $ 969,672 $ 579,486
Accounts receivable, net........................................................ 913,517 745,312
Margin deposits and other prepaid expense....................................... 360,964 152,413
Inventories..................................................................... 124,427 106,536
Restricted cash................................................................. 388,075 176,716
Current derivative assets....................................................... 518,088 330,244
Other current assets............................................................ 78,253 145,323
-------------- --------------
Total current assets......................................................... 3,352,996 2,236,030
-------------- --------------
Restricted cash, net of current portion............................................ 56,099 9,203
Notes receivable, net of current portion........................................... 206,284 195,398
Project development costs.......................................................... 134,359 116,795
Investments in power projects...................................................... 395,374 421,402
Deferred financing costs........................................................... 357,343 185,026
Prepaid lease, net of current portion.............................................. 370,884 301,603
Property, plant and equipment, net................................................. 20,095,964 18,846,580
Goodwill, net...................................................................... 32,720 29,165
Other intangible assets, net....................................................... 93,950 93,066
Long-term derivative assets........................................................ 586,269 496,028
Other assets....................................................................... 354,220 296,696
-------------- --------------
Total assets............................................................... $ 26,036,462 $ 23,226,992
============== ==============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable................................................................ $ 932,554 $ 1,237,261
Accrued payroll and related expense............................................. 70,478 47,978
Accrued interest payable........................................................ 275,784 189,336
Income taxes payable............................................................ 12,968 3,640
Notes payable and borrowings under lines of credit, current portion............. 199,866 509,883
Capital lease obligation, current portion....................................... 3,990 3,454
Construction/project financing, current portion................................. 70,473 1,138,111
Senior notes, current portion................................................... 14,500 --
Current derivative liabilities.................................................. 402,317 189,356
Other current liabilities....................................................... 315,973 248,112
-------------- --------------
Total current liabilities.................................................... 2,298,903 3,567,131
-------------- --------------
Term loan.......................................................................... -- 949,565
Notes payable and borrowings under lines of credit, net of current portion......... 1,070,286 8,249
Capital lease obligation, net of current portion................................... 193,956 197,653
Construction/project financing, net of current portion............................. 4,097,930 3,212,022
Convertible Senior Notes Due 2006.................................................. 1,047,996 1,200,000
Senior notes, net of current portion............................................... 9,248,561 6,894,801
Deferred income taxes, net......................................................... 1,263,091 1,123,729
Deferred lease incentive........................................................... 51,104 53,732
Deferred revenue................................................................... 118,588 154,969
Long-term derivative liabilities................................................... 579,992 528,400
Other liabilities.................................................................. 218,113 175,655
-------------- --------------
Total liabilities.......................................................... 20,188,520 18,065,906
-------------- --------------
Company-obligated mandatorily redeemable convertible preferred securities of
subsidiary trusts................................................................ 1,088,248 1,123,969
Minority interests................................................................. 347,254 185,203
-------------- --------------
-3-
September 30, December 31,
2003 2002
--------------- -------------
(unaudited)
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000 shares;
issued and outstanding one share in 2003 and 2002............................. -- --
Common stock, $.001 par value per share; authorized 1,000,000,000 shares;
issued and outstanding 408,345,564 shares in 2003 and
380,816,132 shares in 2002.................................................... 408 381
Additional paid-in capital...................................................... 2,960,063 2,802,503
Retained earnings............................................................... 1,448,887 1,286,487
Accumulated other comprehensive income (loss)................................... 3,082 (237,457)
-------------- --------------
Total stockholders' equity................................................... $ 4,412,440 $ 3,851,914
-------------- --------------
Total liabilities and stockholders' equity................................... $ 26,036,462 $ 23,226,992
============== ==============
The accompanying notes are an integral part of these consolidated
condensed financial statements.
-4-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 2003 and 2002
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ------------------------------
2003 2002 2003 2002
--------------- ----------- -------------- --------------
Restated(1) Restated(1)
(In thousands, except per share amounts)
(Unaudited)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue......................... $ 1,440,056 $ 943,177 $ 3,634,730 $ 2,272,889
Sales of purchased power for hedging and optimization. 843,013 1,278,520 2,269,102 2,516,727
------------ ----------- ------------ ------------
Total electric generation and marketing revenue..... 2,283,069 2,221,697 5,903,832 4,789,616
Oil and gas production and marketing revenue
Oil and gas sales..................................... 27,879 21,827 83,358 91,031
Sales of purchased gas for hedging and optimization... 305,706 231,893 961,652 664,649
------------ ----------- ------------ ------------
Total oil and gas production and marketing revenue.. 333,585 253,720 1,045,010 755,680
Mark-to-market activities, net
Realized gain (loss) on power and gas transactions,
net................................................. (93) 6,845 30,180 15,276
Unrealized gain (loss) on power and gas transactions,
net................................................. (10,930) (10,957) (18,921) (6,166)
------------ ----------- ------------ ------------
Total mark-to-market activities, net................ (11,023) (4,112) 11,259 9,110
Other revenue............................................ 81,496 3,393 97,596 9,371
------------ ----------- ------------ ------------
Total revenue..................................... 2,687,127 2,474,698 7,057,697 5,563,777
------------ ----------- ------------ ------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense............................... 185,091 141,170 514,518 376,058
Royalty expense....................................... 7,022 4,743 18,840 13,092
Purchased power expense for hedging and optimization.. 835,892 1,059,841 2,254,560 2,039,955
------------ ----------- ------------ ------------
Total electric generation and marketing expense..... 1,028,005 1,205,754 2,787,918 2,429,105
Oil and gas operating and marketing expense
Oil and gas operating expense......................... 24,575 22,953 79,348 67,380
Purchased gas expense for hedging and optimization.... 293,241 218,443 941,312 671,196
------------ ----------- ------------ ------------
Total oil and gas operating and marketing expense... 317,816 241,396 1,020,660 738,576
Fuel expense............................................. 800,270 525,478 2,005,874 1,208,310
Depreciation, depletion and amortization expense......... 148,063 121,667 422,960 320,310
Operating lease expense.................................. 28,439 28,497 84,298 84,877
Other cost of revenue.................................... 8,380 1,354 20,501 4,452
------------ ----------- ------------ ------------
Total cost of revenue............................. 2,330,973 2,124,146 6,342,211 4,785,630
------------ ----------- ------------ ------------
Gross profit................................... 356,154 350,552 715,486 778,147
Income from unconsolidated investments in
power projects............................................ (4,110) (10,176) (68,584) (10,561)
Equipment cancellation and impairment cost.................. 632 10,884 19,940 193,555
Project development expense................................. 2,979 7,624 14,137 29,474
General and administrative expense.......................... 61,757 53,366 179,277 163,614
------------ ----------- ------------ ------------
Income from operations................................... 294,896 288,854 570,716 402,065
Interest expense............................................ 204,668 127,806 496,508 280,628
Distributions on trust preferred securities................. 15,297 15,654 46,610 46,962
Interest income............................................. (10,742) (10,815) (27,782) (32,754)
Minority interest expense................................... 2,569 1,457 10,182 1,870
Other income................................................ (197,725) (35,501) (149,431) (51,802)
------------ ----------- ------------ ------------
Income before provision for income taxes................. 280,829 190,253 194,629 157,161
Provision for income taxes.................................. 41,920 48,386 21,487 33,585
------------ ----------- ------------ ------------
Income before discontinued operations and cumulative
effect of a change in accounting principle............. 238,909 141,867 173,142 123,576
Discontinued operations, net of tax provision (benefit) of
$(778), $4,254, $(7,217) and $10,023...................... (1,127) 9,261 (11,271) 20,200
Cumulative effect of a change in accounting principle,
net of tax provision of $--, $--, $450 and $--............... -- -- 529 --
------------ ----------- ------------ ------------
Net income........................................ $ 237,782 $ 151,128 $ 162,400 $ 143,776
============ =========== ============ ============
-5-
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ------------------------------
2003 2002 2003 2002
--------------- ----------- -------------- --------------
Restated(1) Restated(1)
(In thousands, except per share amounts)
(Unaudited)
Basic earnings per common share:
Weighted average shares of common stock outstanding...... 388,161 376,957 383,447 346,816
Income before discontinued operations and cumulative
effect of a change in accounting principle............. $ 0.62 $ 0.38 $ 0.45 $ 0.36
Discontinued operations, net of tax...................... $ (0.01) $ 0.02 $ (0.03) $ 0.05
Cumulative affect of a change in accounting principle,
net of tax............................................. $ -- $ -- $ -- $ --
------------ ----------- ------------ ------------
Net income........................................ $ 0.61 $ 0.40 $ 0.42 $ 0.41
============ =========== ============ ============
Diluted earnings per common share:
Weighted average shares of common stock outstanding
before dilutive effect of certain convertible securities 394,950 382,607 388,622 355,577
Income before dilutive effect of certain convertible
securities, discontinued operations and cumulative
effect of a change in accounting principle............. $ 0.60 $ 0.37 $ 0.45 $ 0.35
Dilutive effect of certain convertible securities........ $ (0.09) $ (0.05) $ (0.01) $ --
------------ ----------- ------------ ------------
Income before discontinued operations and cumulative
effect of a change in accounting principle............. $ 0.51 $ 0.32 $ 0.44 $ 0.35
Discontinued operations, net of tax...................... $ -- $ 0.02 $ (0.03) $ 0.05
Cumulative effect of a change in accounting principle,
net of tax............................................. $ -- $ -- $ -- $ --
------------ ----------- ------------ ------------
Net income........................................ $ 0.51 $ 0.34 $ 0.41 $ 0.40
============ =========== ============ ============
- ------------
(1) See Note 2 to Consolidated Condensed Financial Statements regarding the
restatement of financial statements.
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, 2003 and 2002
(in thousands)
(unaudited)
Nine Months
Ended
September 30,
2003 2002
-------------- --------------
Restated(1)
Cash flows from operating activities:
Net income...................................................................... $ 162,400 $ 143,776
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization..................................... 489,431 383,370
Equipment cancellation and impairment cost................................... 19,940 193,555
Deferred income taxes, net................................................... 204,900 200,490
Loss (gain) on sale of assets and development cost write-offs, net........... 6,606 (26,225)
Foreign currency translation loss (gain)..................................... 36,234 (995)
Income from unconsolidated investments in power projects..................... (68,584) (10,499)
Distributions from unconsolidated investments in power projects.............. 125,679 2,144
Stock compensation expense................................................... 12,028 --
Gain on repurchase of debt................................................... (192,296) (3,491)
Other........................................................................ 10,505 (1,677)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable........................................................ (161,262) 137,559
Change in net derivative liability......................................... 2,535 (254,185)
Other current assets....................................................... (150,573) 179,349
Other assets............................................................... (142,530) (99,834)
Accounts payable and accrued expense....................................... (197,586) (144,523)
Other liabilities.......................................................... 13,905 100,556
-------------- --------------
Net cash provided by operating activities................................ 171,332 799,370
-------------- --------------
Cash flows from investing activities:
Purchases of property, plant and equipment...................................... (1,523,643) (3,241,929)
Acquisitions, net of cash acquired.............................................. (6,818) --
Disposals of property, plant and equipment...................................... 15,255 125,135
Advances to joint ventures...................................................... (51,945) (64,707)
Decrease (increase) in notes receivable......................................... (13,708) 7,177
Maturities of collateral securities............................................. 4,610 4,633
Project development costs....................................................... (30,184) (84,833)
Decrease (increase) in restricted cash.......................................... (258,255) (10,942)
Cash flows from derivatives not designated as hedges............................ 30,180 15,276
Other........................................................................... (2,073) 7,413
-------------- --------------
Net cash used in investing activities........................................ (1,836,581) (3,242,777)
-------------- ---------------
Cash flows from financing activities:
Repurchase of Zero-Coupon Convertible Debentures Due 2021....................... -- (869,736)
Proceeds from issuance of senior notes.......................................... 3,500,000 --
Repurchases of senior notes..................................................... (906,308) --
Borrowings from notes payable and lines of credit............................... 1,323,618 1,252,453
Repayments of notes payable and lines of credit................................. (1,750,866) (75,734)
Borrowings from project financing............................................... 1,369,900 540,491
Repayments of project financing................................................. (1,395,788) (254,798)
Proceeds from issuance of Convertible Senior Notes Due 2006..................... -- 100,000
Repurchases of Convertible Senior Notes Due 2006................................ (101,887) --
Proceeds from income trust offerings............................................ 126,462 169,400
Proceeds from issuance of common stock.......................................... 8,184 754,818
Proceeds from King City financing transaction................................... 82,000 --
Financing costs................................................................. (244,069) (46,797)
Other........................................................................... 35,243 3,601
-------------- --------------
Net cash provided by financing activities.......................................... 2,046,489 1,573,698
-------------- --------------
-7-
Nine Months
Ended
September 30,
2003 2002
-------------- --------------
Restated(1)
Effect of exchange rate changes on cash and cash equivalents....................... 8,946 2,277
Net increase (decrease) in cash and cash equivalents............................... 390,186 (867,432)
Cash and cash equivalents, beginning of period..................................... 579,486 1,594,144
-------------- --------------
Cash and cash equivalents, end of period........................................... $ 969,672 $ 726,712
============== ==============
Cash paid during the period for:
Interest, net of amounts capitalized............................................ $ 322,051 $ 178,365
Income taxes.................................................................... $ 12,453 $ 13,896
- ------------
(1) See Note 2 to Consolidated Condensed Financial Statements regarding the
restatement of financial statements.
The accompanying notes are an integral part of these consolidated condensed
financial statements.
-8-
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 30, 2003
(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 of America, Canada and the United Kingdom. The Company is involved
in the development, construction, ownership and operation of power generation
facilities and the sale of electricity and its by-product, thermal energy,
primarily in the form of steam. The Company has ownership interests in, and
operates, gas-fired power generation and cogeneration facilities, gas fields,
gathering systems and gas pipelines, geothermal steam fields and geothermal
power generation facilities in the United States of America. In Canada, the
Company owns oil and gas operations and has ownership interests in, and
operates, power facilities. In the United Kingdom, the Company owns and operates
a gas-fired power cogeneration facility. Each of the generation facilities
produces and markets electricity for sale to utilities and other third party
purchasers. Thermal energy produced by the gas-fired power cogeneration
facilities is primarily sold to industrial users. Gas produced, and not
physically delivered to the Company's generating plants, is sold to third
parties.
2. Summary of Significant Accounting Policies
On October 23, 2003, the Company filed a Current Report on Form 8-K (the
"Form 8-K"), which updates its Annual Report on Form 10-K for the year ended
December 31, 2002, as originally filed on March 31, 2003, primarily to reflect
the financial statement effect of reclassifications related to our second
quarter 2003 decision to dispose of our specialty data center engineering
business. The reclassifications were necessary to present the results of this
specialty data center engineering business as discontinued operations for the
three years in the period ended December 31, 2002, in accordance with Financial
Accounting Standards Board ("FASB") Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS
No. 144")." None of the reclassifications affected net income for the three
years ended December 31, 2002.
Restatement of Prior Period Financial Statements - The accompanying
financial statements reflect certain restatements of first, second and third
quarter 2002 amounts, which were included in and described in the Company's
Annual Report on Form 10-K ("Annual Report" or "Form 10-K") for the year ended
December 31, 2002. Subsequent to the issuance of the Company's Consolidated
Condensed Financial Statements as of September 30, 2002, the Company determined
that the sale/leaseback transactions for its Pasadena and Broad River facilities
should have been accounted for as financing transactions, rather than as sales
with operating leases as had been the accounting previously afforded such
transactions. Accordingly, these two transactions were restated as financing
transactions and the proceeds were classified as debt and the operating lease
payments were recharacterized as debt service payments in the accompanying
Consolidated Condensed Financial Statements. The Company is therefore now
accounting for the assets as if they had not been sold. The assets were added
back to the Company's property, plant and equipment, and depreciation has been
recorded thereon.
In addition the Company has reclassified certain amounts in the
accompanying Consolidated Condensed Financial Statements for the three and nine
months ended September 30, 2002, to reflect the adoption of new accounting
standards. The reclassifications include (a) treatment as discontinued
operations pursuant to SFAS No. 144 of the 2002 sales of certain oil and gas
properties, the Company's specialty engineering business and the DePere Energy
Center, (b) the reclassification of revenues and costs associated with certain
energy trading contracts to trading revenues, net, pursuant to Emerging Issues
Task Force ("EITF") Issue No. 02-3, "Issues Related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" ("EITF Issue No.
02-3") and (c) the adoption of SFAS No. 145, "Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" to
reclassify gains or losses from extinguishment of debt from extraordinary gain
or loss to other income or loss.
In October 2002 the EITF released EITF Issue No. 02-3, which precludes
mark-to-market accounting for all energy trading contracts not within the scope
of SFAS No. 133 and mandates 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. EITF Issue No. 02-3
has had no impact on the Company's net income but did affect the presentation of
the prior period Consolidated Financial Statements. Accordingly, the Company
reclassified certain prior period revenue amounts and cost of revenue in its
Consolidated Statements of Operations. The reclassification of the financial
information in accordance with SFAS No. 144, SFAS No. 145 and EITF Issue No.
02-3 discussed above relates exclusively to the presentation and classification
of such amounts and has no effect on net income.
-9-
To properly account for the two sale/leaseback transactions as financing
transactions, to record certain other adjustments, and to reflect the adoption
of new accounting standards as described above, the accompanying Consolidated
Condensed Financial Statements for the three and nine months ended September 30,
2002, have been restated and differ from amounts previously reported in the
Company's Quarterly Report on Form 10Q for the quarter ended September 30, 2002.
A summary of the significant effects of restatement, along with certain
reclassification adjustments, to the consolidated condensed statements of
operations for the three and nine months ended September 30, 2002 is as follows:
As Previously
Three months ended September 30, 2002 Reported As Restated
- --------------------------------------------------------------- --------------- -------------
Sales of purchased power for hedging and optimization.......... $ 1,282,976 $ 1,278,520
Other revenue.................................................. 4,924 3,393
Total revenue.................................................. 2,495,010 2,474,698
Purchased gas expense for hedging and optimization............. 220,775 218,443
Depreciation, depletion and amortization expense............... 117,568 121,667
Operating lease expense........................................ 36,520 28,497
Other cost of revenue.......................................... 3,539 1,354
Gross profit................................................... 362,332 350,552
Equipment cancellation and impairment cost..................... 3,714 10,884
Project development expense.................................... 23,922 7,624
General and administrative expense............................. 57,280 53,366
Income from operations......................................... 277,416 288,854
Interest expense............................................... 113,847 127,806
Provision for income taxes..................................... 48,406 48,386
Income before discontinued operations and extraordinary items.. 144,397 141,867
Discontinued operations, net................................... 16,950 9,261
Net income..................................................... 161,347 151,128
Net income per share - basic................................... 0.43 0.40
Net income per share - diluted................................. 0.36 0.34
As Previously
Nine months ended September 30, 2002 Reported As Restated
- --------------------------------------------------------------- --------------- -------------
Sales of purchased power for hedging and optimization.......... $ 2,526,555 $ 2,516,727
Other revenue.................................................. 14,792 9,371
Total revenue.................................................. 5,586,742 5,563,777
Purchased gas expense for hedging and optimization............. 678,192 671,196
Depreciation, depletion and amortization expense............... 310,943 320,310
Operating lease expense........................................ 108,917 84,877
Other cost of revenue.......................................... 8,333 4,452
Gross profit................................................... 777,341 778,147
Equipment cancellation and impairment cost..................... 172,185 193,555
Project development expense.................................... 59,973 29,474
General and administrative expense............................. 170,369 163,614
Income from operations......................................... 374,814 402,065
Interest expense............................................... 239,112 280,628
Provision for income taxes..................................... 38,805 33,585
Income before discontinued operations and extraordinary items.. 132,646 123,576
Discontinued operations, net................................... 26,950 20,200
Net income..................................................... 159,596 143,776
Net income per share - basic................................... 0.46 0.41
Net income per share - diluted................................. 0.45 0.40
For further information on prior period restatement items, please see Note
2 to the Consolidated Financial Statements included in the Company's Annual
report on Form 10-K for the year ended December 31, 2002, updated by the
Company's Form 8-K, filed on October 23, 2003.
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 accounting
principles generally accepted 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, 2002, which is included in the Company's Annual
Report on Form 10-K, as updated by the Company's Form 8-K, filed on October 23,
2003. The results for interim periods are not necessarily indicative of the
results for the entire year.
-10-
Use of Estimates in Preparation of Financial Statements - The preparation
of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expense during the reporting
period. Actual results could differ from those estimates. The most significant
estimates with regard to these financial statements relate to useful lives and
carrying values of assets (including the carrying value of projects in
development, construction and operation), provision for income taxes, fair value
calculations of derivative instruments and associated reserves, capitalization
of interest and depletion, depreciation and impairment of natural gas and
petroleum property and equipment.
Effective Tax Rate - For the nine months ended September 30, 2003, the
effective rate declined to 11% from 21 % for the nine months ended 2002. This
effective rate variance is due to the inclusion of significant permanent items
in the calculation of the effective rate, which are fixed in amount and have a
significant effect on the effective rates especially as such items become more
material to net income.
New Accounting Pronouncements
In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 applies to fiscal years beginning after June 15,
2002, and amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies." This standard applies to legal obligations associated with
the retirement of long-lived assets that result from the acquisition,
construction, development or normal use of the assets and requires that a
liability for an asset retirement obligation be recognized when incurred,
recorded at fair value and classified as a liability in the balance sheet. When
the liability is initially recorded, the entity will capitalize the cost and
increase the carrying value of the related long-lived asset. Asset retirement
obligations represent future liabilities, and, as a result, accretion expense
will be accrued on this liability until the obligation is satisfied. At the same
time, the capitalized cost will be depreciated over the estimated useful life of
the related asset. At the settlement date, the entity will settle the obligation
for its recorded amount or recognize a gain or loss upon settlement.
The Company adopted the new rules on asset retirement obligations on
January 1, 2003. As required by the new rules, the Company recorded liabilities
equal to the present value of expected future asset retirement obligations at
January 1, 2003. The Company identified obligations related to operating
gas-fired power plants, geothermal power plants and oil and gas properties. The
liabilities are partially offset by increases in net assets, net of accumulated
depreciation, recorded as if the provisions of SFAS 143 had been in effect at
the date the obligation was incurred, which for power plants is generally the
start of commercial operations for the facility.
Based on current information and assumptions, the Company recorded, as of
January 1, 2003, an additional long-term liability of $25.9 million, an
additional asset within property, plant and equipment, net of accumulated
depreciation, of $26.9 million, and a pre-tax gain to income due to the
cumulative effect of a change in accounting principle of $1.0 million. These
entries include the effects of the reversal of site dismantlement and
restoration costs previously expensed in accordance with SFAS No. 19.
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 has adopted, effective January
1, 2003, 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. SFAS No. 146 has not had a material impact on
the Company's Consolidated Condensed Financial Statements.
In November 2002 the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others ("FIN 45")." This Interpretation addresses
the disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under guarantees. In addition, the
Interpretation clarifies the requirements related to the recognition of a
liability by a guarantor at the inception of a guarantee for the obligations
that the guarantor has undertaken in issuing the guarantee. The Company adopted
the disclosure requirements of FIN 45 for the fiscal year ended December 31,
2002, and the recognition provisions on January 1, 2003. Adoption of this
Interpretation did not have a material impact on the Company's Consolidated
Condensed Financial Statements.
-11-
On January 1, 2003, the Company prospectively adopted the fair value method
of accounting for stock-based employee compensation pursuant to SFAS No. 123,
"Accounting for Stock-Based Compensation" as amended by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS No.
148 amends SFAS No. 123 to provide alternative methods of transition for
companies that voluntarily change their accounting for stock-based compensation
from the less preferred intrinsic value based method to the more preferred fair
value based method. Prior to its amendment, SFAS No. 123 required that companies
enacting a voluntary change in accounting principle from the intrinsic value
methodology provided by Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees" could only do so on a prospective
basis; no adoption or transition provisions were established to allow for a
restatement of prior period financial statements. SFAS No. 148 provides two
additional transition options to report the change in accounting principle - the
modified prospective method and the retroactive restatement method.
Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The Company has elected to adopt
the provisions of SFAS No. 123 on a prospective basis; consequently, the Company
is required to provide a pro-forma disclosure of net income and earnings per
share as if SFAS No. 123 accounting had been applied to all prior periods
presented within its financial statements. As shown below, the adoption of SFAS
No. 123 has had a material impact on the Company's financial statements. The
table below reflects the pro forma impact of stock-based compensation on the
Company's net income and earnings per share for the three and nine months ended
September 30, 2003 and 2002, had the Company applied the accounting provisions
of SFAS No. 123 to its prior years' financial statements.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ------------------------------
2003 2002 2003 2002
-------------- -------------- -------------- -------------
Net income
As reported.............................. $ 237,782 $ 151,128 $ 162,400 $ 143,776
Pro Forma................................ 234,353 144,717 148,780 112,001
Earnings per share data:
Basic earnings per share
As reported........................... $ 0.61 $ 0.40 $ 0.42 $ 0.41
Pro Forma............................. 0.60 0.38 0.39 0.32
Diluted earnings per share
As reported........................... $ 0.51 $ 0.34 $ 0.41 $ 0.40
Pro Forma............................. 0.50 0.33 0.38 0.31
Stock-based compensation cost, net of tax,
included in net income, as reported....... $ 3,068 $ -- $ 10,699 $ --
Stock-based compensation cost, net of tax,
included in net income, pro forma......... 6,497 6,411 24,319 31,775
The range of fair values of the Company's stock options granted for the
three months ended September 30, 2003 and 2002, respectively, was as follows,
based on varying historical stock option exercise patterns by different levels
of Calpine employees: $3.58-$3.75 in 2003, $3.00-$3.67 in 2002, on the date of
grant using the Black-Scholes option pricing model with the following
weighted-average assumptions: expected dividend yields of 0%, expected
volatility of 101.49%-106.91% and 66.22%-76.52% for the three months ended
September 30, 2003 and 2002, respectively, risk-free interest rates of
1.42%-1.60% and 2.33%-3.63% for the three months ended September 30, 2003 and
2002, respectively, and expected option terms of 1.5 years and 4-9.5 years for
the three months ended September 30, 2003 and 2002, respectively.
The range of fair values of the Company's stock options granted for the
nine months ended September 30, 2003 and 2002, respectively, was as follows,
based on varying historical stock option exercise patterns by different levels
of Calpine employees: $1.60-$5.16 in 2003, $3.51-$6.94 in 2002, on the date of
grant using the Black-Scholes option pricing model with the following
weighted-average assumptions: expected dividend yields of 0%, expected
volatility of 70.44%-112.99% and 59.30%-76.52% for the nine months ended
September 30, 2003 and 2002, respectively, risk-free interest rates of
1.39%-4.04% and 2.33%-5.42% for the nine months ended September 30, 2003 and
2002, respectively, and expected option terms of 1.5-9.5 years and 4-9.5 years
for the nine months ended September 30, 2003 and 2002, respectively.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). FIN 46
requires the consolidation of entities in which an enterprise absorbs a majority
of the entity's expected losses, receives a majority of the entity's expected
residual returns, or both, as a result of ownership, contractual or other
financial interest in the entity. Historically, entities have generally been
consolidated by an enterprise when it has a controlling financial interest
through ownership of a majority voting interest in the entity. The objectives of
FIN 46 are to provide guidance on the identification of Variable Interest
-12-
Entities ("VIE") for which control is achieved through means other than a
controlling financial interest, and how to determine when and which business
enterprise, the Primary Beneficiary, should consolidate the VIE. This new model
for consolidation applies to an entity in which either (1) the entity lacks
sufficient equity to absorb expected losses without additional subordinated
financial support or (2) its equity holders as a group are not able to make
decisions about the entity's activities. FIN 46 applies immediately to VIEs
created or acquired after January 31, 2003. On October 10, 2003, the FASB issued
FASB Staff Position ("FSP") FIN 46-6, "Effective Date of FASB Interpretation No.
46, 'Consolidation of Variable Interest Entities'" ("FSP FIN 46-6"). FSP FIN
46-6 defers the effective date for the application of FIN 46 to VIEs created
before February 1, 2003 to an entity's first reporting period ending after
December 15, 2003. One possible consequence of FIN 46 is that certain
investments accounted for under the equity method and other off-balance sheet
entities might have to be consolidated. However, based on the Company's
preliminary assessment, and subject to further analysis, the Company does not
believe that FIN 46 will require any of the Company's pre-February 1, 2003
equity method investments or other off-balance sheet entities to be
consolidated.
Acadia Powers Partners, LLC ("Acadia") is the owner of a 1,160-megawatt
electric wholesale generation facility located in Louisiana and is a joint
venture between the Company and Cleco Corporation. The joint venture was formed
in March 2000, but due to a change in the partnership agreement in May 2003, the
Company was required to reconsider its investment in the entity under the FIN 46
guidance. The Company determined that Acadia was a VIE and that it held a
significant variable interest (50%) in the entity. However, the Company was not
the primary beneficiary and therefore not required to consolidate the entity's
assets and liabilities. The net equity in Acadia was approximately $502.0
million as of September 30, 2003. The Company continues to account for this
investment under the equity method. The Company's maximum potential exposure to
loss at September 30, 2003, is limited to the book value of its investment of
approximately $229.2 million.
In April 2003 the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial reporting for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities
under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract
with an initial net investment meets the characteristic of a derivative,
clarifies when a derivative contains a financing component, amends the
definition of an underlying to conform it to language used in FIN 45, and amends
certain other existing pronouncements. SFAS No. 149 is effective for contracts
entered into or modified after June 30, 2003, and should be applied
prospectively, with the exception of certain SFAS No. 133 implementation issues
that were effective for all fiscal quarters prior to June 15, 2003. Any such
implementation issues should continue to be applied in accordance with their
respective effective dates. The adoption of SFAS No. 149 did not have a material
impact on the Company's financial statements.
In May 2003 the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. SFAS
No. 150 applies specifically to a number of financial instruments that companies
have historically presented within their financial statements either as equity
or between the liabilities section and the equity section, rather than as
liabilities. SFAS No. 150 was effective for financial instruments entered into
or modified after May 31, 2003, and otherwise was effective at the beginning of
the first interim period beginning after June 15, 2003.
The Company adopted SFAS No. 150 on July 1, 2003. As a result,
approximately $82 million of mandatorily redeemable noncontrolling interest (not
related to finite-lived subsidiaries) in its King City facility, which had
previously been included within the balance sheet caption "Minority interests",
was reclassified to "Notes payable". Preferential distributions related to this
mandatorily redeemable noncontrolling interest are to be made annually beginning
November 2003 through November 2019 and total approximately $169 million over
the 17-year period. The preferred interest holders' recourse is limited to the
net assets of the entity and the distribution terms defined in the agreement.
The Company has not guaranteed the payment of these preferential distributions.
The distributions and accretion of issuance costs related to this preferred
interest, which was previously reported as a component of "Minority interest
expense" in the Consolidated Condensed Statements of Operations, is now
accounted for as interest expense. Distributions and related accretion
associated with this preferred interest was $2.7 million for the three months
ended September 30, 2003. SFAS No. 150 does not permit reclassification of prior
period amounts to conform to the current period presentation.
During the third quarter of 2003, the Company completed the sales of
preferred equity interests for Auburndale Holdings, LLC and Gilroy Energy Center
("GEC") Holdings, LLC. These interests, in addition to the King City interest,
are classified as debt on the Company's Condensed Consolidated Balance Sheet as
of September 30, 2003. Although the Company cannot readily determine the
-13-
potential cost to repurchase these interests, the carrying value of its
aggregate partners' interests is approximately $244 million.
In November 2003 the FASB indefinitely deferred certain provisions of SFAS
No. 150 as they apply to mandatorily redeemable noncontrolling (minority)
interests associated with finite-lived subsidiaries. Upon the FASB's
finalization of this issue, the Company may be required to reclassify the
minority interest relating to the Company's Canadian Calpine Power Income Fund
("Income Fund") investment to debt. As of September 30, 2003, the minority
interest related to the Income Fund was approximately $310 million. The Company
owns approximately 30% of the fund, which is finite-lived and terminates on
December 31, 2050. The Fund is consolidated due to the Company's exercise of
substantial control over the Income Fund's assets and operations.
The adoption of SFAS No. 150 and related balance sheet reclassifications
did not have an effect on net income or total stockholders' equity but have
impacted the Company's debt-to-equity and debt-to-capitalization ratios.
In June 2003, the FASB issued Derivatives Implementation Group ("DIG")
Issue No. C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly
and Closely Related in Paragraph 10(b) regarding Contracts with a Price
Adjustment Feature." DIG Issue No. C20 superseded DIG Issue No. C11
"Interpretation of Clearly and Closely Related in Contracts That Qualify for the
Normal Purchases and Normal Sales Exception," and specified additional
circumstances in which a price adjustment feature in a derivative contract would
not be an impediment to qualifying for the normal purchases and normal sales
scope exception under SFAS No. 133. DIG Issue No. C20 is effective as of the
first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1,
2003, for the Company) with early application permitted. In conjunction with
initially applying the implementation guidance, DIG Issue No. C20 requires the
recognition of a special transition adjustment for certain contracts containing
a price adjustment feature based on a broad market index for which the normal
purchases and normal sales scope exception had been previously elected. In those
circumstances, the derivative contract should be recognized at fair value as of
the date of the initial application with a corresponding adjustment of net
income as the cumulative effect of a change in accounting principle. It should
then be applied prospectively for all existing contracts as of the effective
date and for all future transactions.
Two of the Company's power sales contracts, which meet the definition of a
derivative and for which it previously elected the normal purchases and normal
sales scope exception, use a CPI or similar index to escalate the Operations and
Maintenance ("O&M") charges. Accordingly, DIG Issue No. C20 has required the
Company to record a special transition accounting adjustment upon adoption of
the new guidance to record these contracts at fair value with a corresponding
adjustment to net income as the effect of a change in accounting principle. The
fair value of these contracts is based in large part on the nature and extent of
the key price adjustment features of the contracts and market conditions on the
date of adoption, such as the forward price of power and natural gas and the
expected future rate of inflation. On October 1, 2003, the Company adopted DIG
Issue No. C20 and recorded other current assets and other assets of
approximately $33.5 million and $260 million, respectively, and a cumulative
effect adjustment to net income of approximately $182 million, net of $111
million of tax. The recorded balance for these contracts will reverse through
charges to income over the life of the long term contracts, which extend out as
far as the year 2023, as deliveries of power are made.
The Company is currently evaluating the potential impact of EITF Issue No.
03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are
Subject to FASB Statement No. 133 and Not `Held for Trading Purposes' As Defined
in EITF Issue No. 02-3: `Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities." In EITF Issue No. 02-3 the Task Force reached a
consensus that companies should present all gains and losses on derivative
instruments held for trading purposes net in the income statement, whether or
not settled physically. EITF Issue No. 03-11 addresses income statement
classification of derivative instruments held for other than trading purposes.
At the July 31, 2003 EITF meeting, the Task Force reached a consensus that
determining whether realized gains and losses on derivative contracts not `held
for trading purposes' should be reported on a net or gross basis is a matter of
judgment that depends on the relevant facts and circumstances. The Task Force
ratified this consensus at its August 13, 2003 meeting, and it is effective
beginning October 1, 2003. The Task Force did not prescribe special effective
date or transition guidance for this Issue. Application of EITF 03-11 may
require or allow the Company to net revenues and expenses associated with
hedging, balancing and optimization ("HBO") activities, which could result in a
substantial reduction in revenues and cost of revenues in future periods but
would not impact gross profit or net income. For the three and nine months ended
September 30, 2003, the Company's HBO revenues were $1.1 billion or 43% of the
Company's total revenue and $3.2 billion or 46% of the Company's total revenue,
respectively. Overall, the Company believes netting its HBO activity would
provide a superior presentation of its true level of activity and growth
patterns compared to the existing gross presentation, so the Company will be
carefully evaluating this new accounting guidance.
-14-
Reclassifications - Prior period amounts in the Consolidated Condensed
Financial Statements have been reclassified where necessary to conform to the
2003 presentation.
3. Property, Plant and Equipment, Net; Capitalized Interest; Project
Development Costs; and Unassigned Equipment in Other Assets
Property, plant and equipment, net, consisted of the following (in
thousands):
September 30 December 31,
2003 2002
-------------- ---------------
Buildings, machinery, and equipment............. $ 13,149,079 $ 10,290,250
Oil and gas properties, including pipelines..... 2,323,328 2,031,026
Geothermal properties........................... 407,953 402,643
Other........................................... 224,942 183,580
-------------- --------------
16,105,302 12,907,499
Less: accumulated depreciation, depletion
and amortization.............................. (1,718,370) (1,220,094)
-------------- --------------
14,386,932 11,687,405
Land............................................ 91,364 82,158
Construction in progress........................ 5,617,668 7,077,017
-------------- --------------
Property, plant and equipment, net.............. $ 20,095,964 $ 18,846,580
============== ==============
Capital Spending - Development and Construction
Construction and development costs consisted of the following at September
30, 2003 (in thousands):
Equipment Project
# of CIP Included in Development Unassigned
Projects CIP Costs Equipment
-------- ------------ ------------ ------------- --------------
Projects in active construction............ 14 $ 4,239,507 $ 1,540,257 $ -- $ --
Projects in advanced development........... 10 666,727 570,967 111,761 --
Projects in suspended development.......... 6 603,505 331,823 13,973 --
Projects in early development.............. 3 3,673 -- 8,625 --
Other capital projects..................... NA 104,256 -- -- --
Unassigned................................. NA -- -- -- 117,795
------------ ------------ ------------- --------------
Total construction and development costs $ 5,617,668 $ 2,443,047 $ 134,359 $ 117,795
============ ============ ============= ==============
Construction in Progress - Construction in progress ("CIP") is primarily
attributable to gas-fired power projects under construction including
prepayments on gas and steam turbine generators and other long lead-time items
of equipment for certain development projects not yet in construction. Upon
commencement of plant operation, these costs are transferred to the applicable
property category, generally buildings, machinery and equipment.
Projects in Active Construction - The 14 projects in active construction
are estimated to come on line from December 2003 to June 2006. These projects
will bring on line approximately 6,720 and 7,863 MW of base load and base load
with peaking capacity, respectively. Interest and other costs related to the
construction activities necessary to bring these projects to their intended use
are being capitalized. The estimated cost to complete these projects, net of
expected project financing proceeds, is approximately $0.8 billion.
Projects in Advanced Development - There are 10 projects in advanced
development. These projects will bring on line approximately 5,439 and 6,505 MW
of base load and base load with peaking capacity, respectively. Interest and
other costs related to the development activities necessary to bring these
projects to their intended use are being capitalized. However, the
capitalization of interest has been suspended on two projects for which
development activities are substantially complete but construction will not
commence until a power purchase agreement and financing are obtained. The
estimated cost to complete the ten projects in advanced development is
approximately $3.2 billion. The Company's current plan is to project finance
these costs as power purchase agreements are arranged.
Suspended Development Projects - Due to current electric market conditions,
the Company has ceased capitalization of additional development costs and
interest expense on certain development projects on which work has been
suspended. Capitalization of costs may recommence as work on these projects
resumes, if certain milestones and criteria are met. These projects would bring
on line approximately 2,938 and 3,418 MW of base load and base load with peaking
capacity, respectively. The estimated cost to complete these projects is
approximately $1.4 billion.
-15-
Projects in Early Development - Costs for projects that are in early stages
of development are capitalized only when it is highly probable that such costs
are ultimately recoverable and significant project milestones are achieved.
Until then all costs, including interest costs are expensed. The projects in
early development with capitalized costs relate to three projects and include
geothermal drilling costs and equipment purchases.
Other Capital Projects - Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development, as well as software developed for internal use.
Unassigned Equipment - As of September 2003, the Company had made progress
payments on 7 turbines, 1 heat recovery steam generator and other equipment with
an aggregate carrying value of $117.8 million. This unassigned equipment is
classified on the balance sheet as other assets because it is not assigned to
specific development and construction projects. The Company is holding this
equipment for potential use on future projects. It is possible that some of this
unassigned equipment may eventually be sold, potentially in combination with the
Company's engineering and construction services. For equipment that is not
assigned to development or construction projects, interest is not capitalized.
Capitalized Interest - The Company capitalizes interest on capital invested
in projects during the advanced stages of development and the construction
period in accordance with SFAS No. 34, "Capitalization of Interest Cost," 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. For the three months ended September 30, 2003
and 2002, the total amount of interest capitalized was $98.7 million and $123.2
million, respectively, including $13.0 million and $22.2 million, respectively,
of interest incurred on funds borrowed for specific construction projects and
$85.7 million and $101.0 million, respectively, of interest incurred on general
corporate funds used for construction. For the nine months ended September 30,
2003 and 2002, the total amount of interest capitalized was $333.7 million and
$457.3 million, respectively, including $51.4 million and $94.3 million,
respectively, of interest incurred on funds borrowed for specific construction
projects and $282.3 million and $363.0 million, respectively, of interest
incurred on general corporate funds used for construction. Upon commencement of
plant operation, capitalized interest, as a component of the total cost of the
plant, is amortized over the estimated useful life of the plant. The decrease in
the amount of interest capitalized during the three and nine months ended
September 30, 2003 reflects the completion of construction for several power
plants and the result of the current suspension of certain of the Company's
development projects.
In accordance with SFAS No. 34, the Company determines which debt
instruments best represent a reasonable measure of the cost of financing
construction assets in terms of interest cost incurred that otherwise could have
been avoided. These debt instruments and associated interest cost are included
in the calculation of the weighted average interest rate used for capitalizing
interest on general funds. The primary debt instruments included in the rate
calculation of interest incurred on general corporate funds are the Company's
Senior Notes, the Company's term loan facilities and the secured working capital
revolving credit facility.
Impairment Evaluation - All construction and development projects,
including unassigned turbines are reviewed for impairment whenever there is an
indication of potential reduction in a project's fair value. Equipment assigned
to such projects is not evaluated for impairment separately, as it is integral
to the assumed future operations of the project to which it is assigned. If it
is determined that it is no longer probable that the projects will be completed
and all capitalized costs recovered through future operations, the carrying
values of the projects would be written down to the recoverable value in
accordance with the provisions of SFAS No. 144. The Company reviews its other
unassigned equipment for potential impairment based on probability-weighted
alternatives of utilizing the equipment for future projects versus selling the
equipment. Utilizing this methodology, the Company does not believe that the
equipment not committed to sale is impaired. However, during the second quarter
of 2003, the Company recorded approximately $17.2 million in losses in
connection with the sale of two turbines, and it may incur further losses should
it decide to sell more unassigned equipment in the future.
4. Goodwill and Other Intangible Assets
Recorded goodwill was $32.7 million and $29.2 million as of September 30,
2003, and December 31, 2002, respectively, and is included in the corporate and
other reporting unit.
The increase in goodwill during 2003 is due to a $3.5 million accrual in
anticipation of certain contingent payments that the Company will pay in
December 2003 related to performance incentives under the terms of the Power
Systems Manufacturing ("PSM") purchase agreement.
-16-
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):
Weighted
Average As of September 30, 2003 As of December 31, 2002
Useful ----------------------------- ----------------------------
Life/Contract Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------- ----------- ------------ ----------- ------------
Patents......................... 5 $ 485 $ (303) $ 485 $ (231)
Power sales agreements.......... 23 86,962 (39,361) 156,814 (106,227)
Fuel supply and fuel management
contracts..................... 26 22,198 (4,771) 22,198 (4,105)
Geothermal lease rights......... 20 19,518 (425) 19,518 (350)
Steam purchase agreement........ 14 5,370 (785) 5,201 (486)
Other........................... 5 5,232 (170) 320 (71)
----------- ---------- ----------- ----------
Total........................ $ 139,765 $ (45,815) $ 204,536 $ (111,470)
=========== ========== =========== ==========
Amortization expense of other intangible assets was $1.2 million and $6.1
million in the three months ended September 30, 2003 and 2002, respectively, and
$4.2 million and $17.8 million in the nine months ended September 30, 2003 and
2002, respectively. Assuming no future impairments of these assets or additions
as the result of acquisitions, amortization expense for the twelve months ended
December 31 will be $5.4 million in 2003, $4.9 million in 2004, $4.8 million in
2005, $4.8 million in 2006 and $4.8 million in 2007.
5. Financing
On July 10, 2003, the Company renegotiated its financing agreement with
Siemens Westinghouse Power Corporation to extend the monthly payment due dates
through January 28, 2005. The Company repaid $81.2 million of the outstanding
balance during the three months ended September 30, 2003. At September 30, 2003,
there was $134.7 million outstanding under this agreement.
On July 16, 2003, the Company closed its $3.3 billion term loan and
second-priority senior secured notes offering ("$3.3 billion offering"). The
term loan and senior notes are secured by substantially all of the assets owned
directly by Calpine Corporation, including natural gas and power plant assets
and the stock of Calpine Energy Services and other subsidiaries. The offering
was comprised of two tranches of floating rate securities and two tranches of
fixed rate securities. The floating rate securities included a $750 million,
four-year term loan priced at LIBOR plus 575 basis points and $500 million of
Second-Priority Senior Secured Floating Rate Notes due 2007 also priced at LIBOR
plus 575 basis points. The fixed rate securities included $1.15 billion of 8.5%
Second Priority Senior Secured Notes due 2010 and $900 million of 8.75% Second
Priority Senior Secured Notes due 2013.
On July 16, 2003, the Company entered into agreements for a new $500
million working capital facility. The new first-priority senior secured facility
consists of a two-year, $300 million working capital revolver and a four-year,
$200 million term loan that together provide up to $500 million in combined cash
borrowing and letter of credit capacity. The new facility replaced the Company's
prior working capital facilities and is secured by a first-priority lien on the
same assets that collateralize the Company's recently completed $3.3 billion
term loan and second-priority senior secured notes offering.. The $949.6 million
outstanding under the Company's secured term credit facility and the $555.5
million outstanding under the Company's revolving credit facilities were repaid
on July 16, 2003, with the proceeds of the $3.3 billion offering.
On July 16, 2003, the Company entered into a cash collateralized letter of
credit facility with The Bank of Nova Scotia under which it can issue up to $200
million of letters of credit through July 15, 2005. As of September 30, 2003,
the Company had $129.7 million of letters of credit issued under this facility,
with a corresponding amount of cash on deposit and held by The Bank of Nova
Scotia as collateral, which was classified as restricted cash in the Company's
Consolidated Condensed Balance Sheet.
On July 17, 2003, Standard & Poor's placed the Company's corporate rating
(currently rated at B), its senior unsecured debt rating (currently at CCC+),
its preferred stock rating (currently at CCC), its bank loan rating (currently
at B), and its second priority senior secured debt rating (currently at B) under
review for possible downgrade.
On July 21, 2003, the Company repaid the $50.0 million outstanding balance
on its peaker financing.
-17-
On July 23, 2003, Fitch, Inc. downgraded the Company's long-term senior
unsecured debt rating from B+ to B- (with a stable outlook), its preferred stock
rating from B- to CCC (with a stable outlook), and initiated coverage of its
senior secured debt rating at BB- (with a stable outlook).
Debt securities repurchased by the Company during the third quarter were
approximately $1.2 billion in aggregate outstanding principal amount at a
redemption price of $992.1 million plus accrued interest to the redemption
dates. The Company recorded a pre-tax gain on these transactions in the amount
of $185.1 million, net of write-offs of unamortized deferred financing costs and
the unamortized premiums or discounts. The following table summarizes the total
debt securities repurchased by the Company during the three months ended
September 30, 2003 (in millions):
Principal Redemption
Debt Security Amount Amount
- ---------------------------------------------------- ----------- ----------
Convertible Senior Notes Due 2006................... $ 112.0 $ 100.5
8-1/4% Senior Notes Due 2005........................ 25.0 24.5
10-1/2% Senior Notes Due 2006....................... 5.2 5.1
7-5/8% Senior Notes Due 2006........................ 35.3 32.5
8-3/4% Senior Notes Due 2007........................ 48.9 45.0
7-7/8% Senior Notes Due 2008........................ 52.4 41.1
8-1/2% Senior Notes Due 2008........................ 48.3 42.3
8-3/8% Senior Notes Due 2008........................ 59.6 46.9
7-3/4% Senior Notes Due 2009........................ 77.0 61.2
8-5/8% Senior Notes Due 2010........................ 185.9 152.2
8-1/2% Senior Notes Due 2011........................ 437.6 361.1
8-7/8% Senior Notes Due 2011........................ 104.5 79.7
----------- ---------
$ 1,191.7 $ 992.1
=========== =========
Debt securities and Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trusts ("HIGH TIDES") exchanged for Calpine
common stock in privately negotiated transactions during the third quarter were
$157.5 million in principal amount for 25.2 million Calpine common shares. The
Company recorded a $22.6 million pre-tax gain on these transactions, net of
write-offs of unamortized deferred financing costs and the unamortized premiums
or discounts. The following table summarizes the total debt securities and HIGH
TIDES exchanged for common stock by the Company for the three months ended
September 30, 2003 (in millions):
Common
Principal Stock
Debt Securities and HIGH TIDES Amount Issued
- ---------------------------------------------------- ----------- ----------
Convertible Senior Notes Due 2006................... $ 40.0 7.2
8-1/2% Senior Notes Due 2008........................ 55.0 8.1
8-1/2% Senior Notes Due 2011........................ 25.0 3.4
HIGH TIDES I........................................ 37.5 6.5
----------- ----
$ 157.5 25.2
=========== ====
At September 30, 2003, the total Senior Notes balance was $9,263.1 million.
This total is comprised of $200.0 million of First Priority Senior Secured
Senior Notes, $3,300.0 million of Second Priority Senior Secured Notes and
$5,763.1 million of unsecured Senior Notes. All of the above notes are
obligations of or with recourse to the Company.
On August 4, 2003, the Company announced plans to sell its unconsolidated,
50-percent interest in the 240-MW Gordonsville Power Plant to Dominion Virginia
Power, an affiliate of Dominion. Under the terms of the transaction, the Company
will receive a $31.5 million cash payment, which includes a $26 million payment
from Dominion and a separate $5.5 million payment from the project for return of
a debt service reserve. The Company's 50-percent share of the project's
non-recourse debt at September 30, 2003, was $43.6 million. The Company expects
to complete the transaction in the fourth quarter of 2003, pending regulatory
and other third-party approvals.
On August 14, 2003, the Company's wholly owned subsidiaries, Calpine
Construction Finance Company, L.P. ("CCFC I") and CCFC Finance Corp., closed a
$750 million institutional term loans and secured notes offering, proceeds from
which were utilized to repay a majority of CCFC I's indebtedness which would
have matured in the fourth quarter of 2003. The offering included $385 million
of First Priority Secured Institutional Term Loans Due 2009 offered at 98% of
par and priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis
points, and $365 million of Second Priority Senior Secured Floating Rate Notes
Due 2011 offered at 98.01% of par and priced at LIBOR plus 850 basis points,
with a LIBOR floor of 125 basis points. The noteholders' recourse is limited to
seven of CCFC I's natural gas-fired electric generating facilities located in
various power markets in the United States, and related assets and contracts.
S&P has assigned a B corporate credit rating to CCFC I. S&P also assigned a B+
-18-
rating (with a negative outlook) to the First Priority Secured Institutional
Term Loans Due 2009 and a B- rating (with a negative outlook) to the Second
Priority Secured Floating Rate Notes Due 2011.
One of the Company's wholly owned subsidiaries, South Point Energy Center,
LLC, leases the 530-MW South Point power facility located in Arizona, pursuant
to certain facility lease agreements. The Company became aware that a technical
default had occurred under such facility lease agreements as a result of an
inadvertent pledge of the ownership interests in such subsidiary granted
pursuant to certain separate loan facilities entered into by the Company. The
South Point facility lease was entered into as part of a larger transaction,
which also involved the lease by two other subsidiaries of the Company of the
following two power facilities: the 850-MW Broad River power facility located in
South Carolina, and the 520-MW RockGen power facility located in Wisconsin. As
all three lease transactions were part of the same overall transaction, the
facility lease agreements for Broad River and RockGen contain cross-default
provisions to the South Point facility lease agreements and, therefore, a
technical default also existed under the Broad River and RockGen facility lease
agreements. However, upon the release of the inadvertent South Point pledge,
which occurred in September 2003, the defaults under the Broad River, RockGen
and South Point facility lease agreements were cured.
On August 25, 2003, the Company announced that it had completed a $230
million non-recourse project financing for its 600-megawatt Riverside Energy
Center. The natural gas-fueled electric generating facility is currently under
construction in Beloit, Wisconsin. Upon completion of the project, which is
scheduled for June 2004, Calpine will sell 450 megawatts of electricity to
Wisconsin Power and Light under the terms of a nine-year tolling agreement and
provide 75 megawatts of capacity to Madison Gas & Electric under a nine-year
power sales agreement. A group of banks, including Credit Lyonnais, Co-Bank,
Bayerische Landesbank, HypoVereinsbank and NordLB, will finance construction of
the plant at a rate of Libor plus 250 basis points. Upon commercial operation of
the Riverside Energy Center, the banks will provide a three-year term-loan
facility initially priced at Libor plus 275 basis points. At September 30, 2003,
there was $133.2 million outstanding under this project financing.
On September 3, 2003, the Company announced that it had completed the sale
of a 70-percent preferred interest in its Auburndale power plant to Pomifer
Power Funding, LLC, ("PPF"), a subsidiary of ArcLight Energy Partners Fund I,
L.P., for $88.0 million. This preferred interest meets the criteria of a
mandatorily redeemable financial instrument and has been classified as debt
under the guidance of SFAS No. 150, due to certain preferential distributions to
PPF. The preferential distributions are to be paid quarterly beginning in
November 2003 and total approximately $204.7 million over the 11-year period.
The preferred interest holders' recourse is limited to the net assets of the
entity and distribution terms are defined in the agreement. The Company has not
guaranteed the payment of these preferential distributions. Calpine will hold
the remaining interest in the facility and will continue to provide operations
and maintenance services.
On September 25, 2003, the Company's wholly owned subsidiaries, CCFC I and
CCFC Finance Corp., closed a $50 million add-on financing to the $750 million
CCFC I offering completed on August 14, 2003, described above.
On September 30, 2003, the Company's Gilroy Energy Center, LLC ("GEC"), a
wholly owned, stand-alone subsidiary of the Company's subsidiary GEC Holdings,
LLC, closed on $301.7 million of 4% Senior Secured Notes Due 2011. The senior
secured notes are secured by GEC's and its subsidiaries' 11 peaking units
located at nine power-generating sites in northern California. The notes also
are secured by a long-term power sales agreement for 495 megawatts of peaking
capacity with the State of California Department of Water Resources, which is
being served by the 11 peaking units. In addition, payment of the principal and
interest on the notes when due is insured by an unconditional and irrevocable
financial guaranty insurance policy that was issued simultaneously with the
delivery of the notes. Proceeds of the notes offering (after payment of
transaction expenses, including payment of the financial guaranty insurance
premium, which are capitalized and included in deferred financing costs on the
balance sheet) will be used to reimburse costs incurred in connection with the
development and construction of the peaker projects. The noteholders' recourse
is limited to the financial guaranty insurance policy and, insofar as payment
has not been made under such policy, to the assets of GEC and its subsidiaries.
The Company has not guaranteed repayment of the notes. In connection with this
offering, the Company has received funding on a third party preferred equity
investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest
meets the criteria of a mandatorily redeemable financial instrument and has been
classified as debt under the guidance of SFAS No. 150, due to certain
preferential distributions to the third party. The preferential distributions
are due bi-annually beginning in March 2004 through September 2011 and total
approximately $113.3 million over the eight-year period. The preferred interest
holders' recourse is limited to the net assets of the entity and distribution
terms are defined in the agreement. The Company has not guaranteed the payment
of these preferential distributions.
The Company is a party to a Letter of Credit and Reimbursement Agreement
dated as of December 19, 2000, with Credit Suisse First Boston ("CSFB"),
-19-
pursuant to which CSFB issued a letter of credit with a maximum face amount of
$78.3 million for the Company's account, approximately 50% of which is secured
by a letter of credit issued by another bank. CSFB has advised the Company that
CSFB believes that the Company may have failed to comply with certain covenants
under the Letter of Credit and Reimbursement Agreement relating to the Company's
ability to incur indebtedness and grant liens, and has requested that the
Company provide security for the remaining unsecured balance outstanding under
the CSFB letter of credit. The Company believes it has complied with such
covenants and is in active discussions with CSFB concerning this matter. The
Company does not believe this matter will have a material adverse effect on the
Company.
6. Investments in Power Projects
The Company's investments in power projects are integral to its operations.
In accordance with APB Opinion No. 18, "The Equity Method of Accounting For
Investments in Common Stock" and FASB Interpretation No. 35, "Criteria for
Applying the Equity Method of Accounting for Investments in Common Stock (An
Interpretation of APB Opinion No. 18)," they are accounted for under the equity
method, and are as follows (in thousands):
Ownership
Interest as of Investment Balance at
September 30, September 30, December 31,
2003 2003 2002
-------------- -------------- --------------
Acadia Power Plant........................... 50.0% $ 229,215 $ 282,634
Grays Ferry Power Plant...................... 40.0% 39,453 42,322
Aries Power Plant............................ 50.0% 59,033 30,936
Gordonsville Power Plant..................... 50.0% 25,073 20,892
Androscoggin Power Plant..................... 32.3% 9,785 9,383
Whitby Cogeneration.......................... 20.8% 31,045 33,502
Other........................................ -- 1,770 1,733
------------- ------------
Total investments in power projects....... $ 395,374 $ 421,402
============ ============
The debt on the books of the unconsolidated power projects is not reflected
on the Company's consolidated condensed balance sheet. At September 30, 2003,
based on the Company's pro rata ownership share of each of the investments, the
Company's share of the combined debt balance of $533.6 million would be
approximately $193.4 million. However, all such debt is non-recourse to the
Company.
The Company owns a 32.3% interest in the unconsolidated equity method
investee Androscoggin Energy LLC ("AELLC"). AELLC owns the 160-MW Androscoggin
Energy Center located in Maine and has construction debt of $62.6 million
outstanding as of September 30, 2003. The debt is non-recourse to Calpine
Corporation (the "AELLC Non-Recourse Financing"). On September 30, 2003, the
Company's investment balance was $9.8 million and its notes receivable balance
due from AELLC was $12.0 million. On August 8, 2003, AELLC received a letter
from the lenders claiming that certain events of default have occurred under the
credit agreement for the AELLC Non-Recourse Financing, including, among other
things, that the project has been and remains in default under its debt
agreement because the lending syndication had declined to extend the dates for
the conversion of the construction loan by a certain date. AELLC is currently
discussing with the banks a forbearance arrangement until an agreement is
reached concerning the extension, conversion or repayment of the debt; however,
the outcome is uncertain at this point. Also, the steam host for the AELLC
project, International Paper Company ("IP"), filed a complaint against AELLC in
October 2000, which is disclosed in Note 12 "Commitments and Contingencies."
IP's complaint has been a complicating factor in converting the construction
debt to long term financing.
The Company also owns a 50% interest in the unconsolidated equity method
investee Merchant Energy Partners Pleasant Hill, LLC ("Aries"). Aries owns the
591-MW Aries Power Project located in Pleasant Hill, Missouri, and has
construction debt of $190.0 million as of September 30, 2003, that was due on
June 26, 2003. Due to the default, the partners were required to contribute
their proportionate share of $75 million in additional equity. During the second
quarter, the Company drew down $37.5 million under its working capital revolver
to fund its equity contribution. The management of Aries is in negotiation with
the lenders to extend the debt while it continues to negotiate a term loan for
the project. The project is technically in default of its debt agreement until
the extension is signed. The Company believes that the project will be able to
obtain long-term project financing at commercially reasonable terms. As a result
of this event, the Company has reviewed its $59.0 million investment in the
Aries project and believes that the investment is not impaired.
-20-
The following details the Company's income and distributions from its
investments in unconsolidated power projects (in thousands):
Income Distributions
Ownership ----------------------- -----------------------
Interest For the Nine Months Ended September 30,
--------- -------------------------------------------------
2003 2002 2003 2002
---------- ---------- ----------- -------
Acadia Power Plant (1)............ 50.0% $ 70,990 $ 6,713 $ 124,613 $ --
Gordonsville Power Plant.......... 50.0% 4,155 4,159 1,050 2,125
Lockport Power Plant (2).......... --% -- 1,570 -- --
Whitby Cogeneration............... 20.8% 788 438 -- --
Aries Power Plant................. 50.0% (539) 1,454 -- --
Androscoggin Power Plant.......... 32.3% (5,157) (2,028) -- --
Grays Ferry Power Plant........... 40.0% (1,864) (1,453) -- --
Other............................. -- 211 (292) 17 19
---------- ---------- ----------- -------
Total.......................... $ 68,584 $ 10,561 $ 125,680 $ 2,144
========== ========== ============ =======
The Company provides for deferred taxes to the extent that distributions
exceed earnings.
(1) On May 12, 2003, the Company completed the restructuring of its interest in
Acadia. As part of the transaction, the partnership terminated its 580-MW,
20-year tolling arrangement with a subsidiary of Aquila in return for a
cash payment of $105.5 million. Acadia recorded a gain of $105.5 million
and then made a $105.5 million distribution to Calpine. Subsequently, CES,
a wholly owned subsidiary of Calpine, entered into a new 20-year, 580-MW
tolling contract with Acadia. CES will now market all of the output from
the Acadia Power Project under the terms of this new contract and an
existing 20-year tolling agreement. Cleco will receive priority cash
distributions as its consideration for the restructuring. As a result of
this transaction, the Company recorded, as its share of the termination
payment from the Aquila subsidiary, a $52.8 million gain which was recorded
within income from unconsolidated investments in power projects. Due to the
restructuring of its interest in Acadia, the Company was required to
reconsider its investment in the entity under FIN 46. See Note 2 "Summary
of Significant Accounting Policies" for further information.
(2) On March 29, 2002, the Company sold its 11.4% interest in the Lockport
Power Plant in exchange for a $27.3 million note receivable, which was
subsequently paid in full, from Fortistar Tuscarora LLC, a wholly owned
subsidiary of Fortistar LLC, the project's managing general partner. This
transaction resulted in a pre-tax gain of $9.7 million recorded in other
income.
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 and selectively disposing of certain less
strategically important assets, which serves primarily to raise cash for general
corporate purposes and strengthen the Company's balance sheet through repayment
of debt. Set forth below are all of the Company's asset disposals by reportable
segment that impacted the Company's Consolidated Condensed Financial Statements
for the nine months ended September 30, 2003 and 2002:
Corporate and Other
On July 31, 2003, the Company completed the sale of its specialty data
center engineering business and recorded a pre-tax loss on the sale of $11.6
million.
Oil and Gas Production and Marketing
On August 29, 2002, the Company completed the sale of certain oil and gas
properties ("Medicine River properties") located in central Alberta to NAL Oil
and Gas Trust and another institutional investor for Cdn$125.0 million (US$80.1
million). As a result of the sale, the Company recorded a pre-tax gain of $21.9
million in the third quarter 2002.
On October 1, 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$244.3
million). Of the total consideration, the Company received US$155.9 million in
cash. The remaining US$88.4 million of consideration was paid by Pengrowth
Corporation's purchase in the open market of US$203.2 million in aggregate
principal amount of the Company's debt securities. As a result of the
transaction, the Company recorded a US$37.4 million pre-tax gain on the sale of
the properties and a gain on the extinguishment of debt of US$114.8 million in
-21-
the fourth quarter 2002. The Company also used approximately US$50.4 million of
cash proceeds to repay amounts outstanding under its US$1.0 billion term loan.
On October 31, 2002, the Company sold all of its oil and gas properties in
Drake Bay Field located in Plaquemines Parish, Louisiana for approximately $3
million to Goldking Energy Corporation. As a result of the sale, the Company
recognized a pre-tax loss of $0.02 million in the fourth quarter 2002.
Electric Generation and Marketing
On December 16, 2002, the Company completed the sale of the 180-MW DePere
Energy Center in DePere, Wisconsin. The facility was sold to Wisconsin Public
Service for $120.4 million, which included $72.0 million in cash at closing and
a $48.4 million payment due in December 2003. As a result of the sale, the
Company recognized a pre-tax gain of $35.8 million. On December 17, 2002, the
Company sold its right to the December 2003 payment to a third party for $46.3
million, and recognized a pre-tax loss of $2.1 million.
Summary
The table below presents significant components of the Company's income
from discontinued operations for the three and nine months ended September 30,
2003 and 2002, respectively (in thousands):
Three Months Ended September 30, 2003
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- ------------
Total revenue............................................ $ -- $ -- $ -- $ --
============ ============ ============= ============
Loss on disposal before taxes............................ $ -- $ -- $ (8,277) $ (8,277)
Operating loss from discontinued operations
before taxes........................................... -- -- 6,372 6,372
------------ ------------ ------------- ------------
Loss from discontinued operations, before taxes.......... $ -- $ -- $ (1,905) $ (1,905)
============ ============ ============= ============
Loss on disposal, net of tax............................. $ -- $ -- $ (5,130) $ (5,130)
Operating loss from discontinued operations,
net of tax............................................. -- -- 4,003 4,003
------------ ------------ ------------- ------------
Loss from discontinued operations, net of tax............ $ -- $ -- $ (1,127) $ (1,127)
============ ============ ============= ============
Nine Months Ended September 30, 2003
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- ------------
Total revenue............................................ $ -- $ -- $ -- $ --
============ ============ ============= ============
Loss on disposal before taxes............................ $ -- $ -- $ (11,571) $ (11,571)
Operating loss from discontinued operations
before taxes........................................... -- -- (6,917) (6,917)
------------ ------------ ------------- ------------
Loss from discontinued operations, before taxes.......... $ -- $ -- $ (18,488) $ (18,488)
============ ============ ============= ============
Loss on disposal, net of tax............................. $ -- $ -- $ (7,172) $ (7,172)
Operating loss from discontinued operations,
net of tax............................................. -- -- (4,099) (4,099)
------------ ------------ ------------- ------------
Loss from discontinued operations, net of tax............ $ -- $ -- $ (11,271) $ (11,271)
============ ============ ============= ============
Three Months Ended September 30, 2002
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- ------------
Total revenue............................................ $ 5,095 $ 26,369 $ 1,531 $ 32,995
============ ============ ============= ============
Gain on disposal before taxes............................ $ -- $ 21,891 $ -- $ 21,891
Operating income (loss) from discontinued operations
before taxes........................................... 1,243 4,146 (13,765) (8,376)
------------ ------------ ------------- ------------
Income (loss) from discontinued operations, before taxes. $ 1,243 $ 26,037 $ (13,765) $ 13,515
============ ============ ============= ============
-22-
Three Months Ended September 30, 2002
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- ------------
Gain on disposal, net of tax............................. $ -- $ 13,026 $ -- $ 13,026
Operating income from discontinued operations,
net of tax............................................. 753 3,638 (8,156) (3,765)
------------ ------------ ------------- ------------
Income (loss) from discontinued operations, net of tax... $ 753 $ 16,664 $ (8,156) $ 9,261
============ ============ ============= ============
Nine Months Ended September 30, 2002
--------------------------------------------------------
Electric Oil and Gas Corporate
Generation Production and
and Marketing and Marketing Other Total
------------- ------------- ------------- ------------
Total revenue............................................ $ 12,057 $ 73,931 $ 5,359 $ 91,347
============ ============ ============= ============
Gain on disposal before taxes............................ $ -- $ 21,891 $ -- $ 21,891
Operating income (loss) from discontinued operations
before taxes........................................... 3,824 18,260 (13,752) 8,332
------------ ------------ ------------- ------------
Income (loss) from discontinued operations, before taxes. $ 3,824 $ 40,151 $ (13,752) $ 30,223
============ ============ ============= ============
Gain on disposal, net of tax............................. $ -- $ 13,026 $ -- $ 13,026
Operating income (loss) from discontinued operations,
net of tax............................................. 2,510 12,812 (8,148) 7,174
------------ ------------ ------------- ------------
Income (loss) from discontinued operations, net of tax... $ 2,510 $ 25,838 $ (8,148) $ 20,200
============ ============ ============= ============
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 Issue No. 87-24"). Also in accordance with EITF
Issue 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 was
required to repay under the terms of its $1.0 billion term loan. For the three
and nine months ended September 30, 2002, the Company allocated interest expense
of $2.8 million and $5.8 million, respectively, to its discontinued operations.
No interest expense was allocated to discontinued operations in 2003.
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 instruments to convert
floating or indexed electricity and gas (and to a lesser extent oil and refined
product) prices to fixed prices in order to lessen its vulnerability to
reductions in electric prices for the electricity it generates 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 it is able to achieve from these
assets. From time to time the Company has entered into contracts considered
energy trading contracts under EITF Issue No. 02-3. However, the Company's
traders have low capital at risk and value at risk limits for energy trading,
and its risk management policy limits, at any given time, its net sales of power
to its generation capacity and limits its net purchases of gas to its fuel
consumption requirements on a total portfolio basis. This model is markedly
different from that of companies that engage in significant commodity trading
operations that are unrelated to underlying physical assets. Derivative
commodity instruments are accounted for under the requirements of SFAS No. 133.
-23-
The Company also routinely enters into physical commodity contracts for
sales of its generated electricity and purchases of natural gas to ensure
favorable utilization of generation and production assets. Such contracts often
meet the criteria of SFAS No. 133 as derivatives but are generally eligible for
the normal purchases and sales exception. Some of those contracts that are not
deemed normal purchases and sales can be designated as hedges of the underlying
consumption of gas or production of electricity.
Interest Rate and Currency Derivative Instruments
The Company also enters into various interest rate swap agreements to hedge
against changes in floating interest rates on certain of its 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.
The table below reflects the amounts (in thousands) that are recorded as
assets and liabilities at September 30, 2003, for the Company's derivative
instruments:
Interest Commodity
Rate Derivative Total
Derivative Instruments Derivative
Instruments Net Instruments
------------ --------------- ---------------
Current derivative assets............................ $ -- $ 518,088 $ 518,088
Long-term derivative assets.......................... -- 586,269 586,269
------------ --------------- ---------------
Total assets...................................... $ -- $ 1,104,357 $ 1,104,357
============ =============== ===============
Current derivative liabilities....................... $ (14,490) $ (387,827) $ (402,317)
Long-term derivative liabilities..................... (24,299) (555,693) (579,992)
------------ --------------- ---------------
Total liabilities................................. $ (38,789) $ (943,520) $ (982,309)
============ =============== ===============
Net derivative assets (liabilities).................. $ (38,789) $ 160,837 $ 122,048
============ =============== ===============
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, 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 initially hedged transactions occur. As
a result, there will be a temporary difference between OCI and
derivative assets and liabilities on the books until the remaining OCI
balance is recognized in earnings.
-24-
Below is a reconciliation from the Company's net derivative assets to its
accumulated other comprehensive loss, net of tax from derivative instruments at
September 30, 2003 (in thousands):
Net derivative assets........................................... $ 122,048
Derivatives not designated as cash flow hedges and
recognized hedge ineffectiveness.............................. (147,803)
Cash flow hedges terminated prior to maturity................... (183,058)
Deferred tax asset attributable to accumulated other
comprehensive loss on cash flow hedges........................ 85,478
Accumulated OCI from unconsolidated investees................... (6,052)
-------------
Accumulated other comprehensive loss from derivative
instruments, net of tax (1)................................... $ (129,387)
=============
- ------------
(1) Amount represents one portion of the Company's total accumulated OCI
balance. See Note 9 - "Comprehensive Income (Loss)" for further
information.
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, 2003.
September 30, 2003
-----------------------------
Gross Net
------------- -------------
Current derivative assets.................. $ 992,231 $ 518,088
Long-term derivative assets................ 1,283,040 586,269
------------- -------------
Total derivative assets................. $ 2,275,271 $ 1,104,357
============= =============
Current derivative liabilities............. $ (862,614) $ (387,827)
Long-term derivative liabilities........... (1,251,820) (555,693)
------------- -------------
Total derivative liabilities............ $ (2,114,434) $ (943,520)
============= =============
Net commodity derivative assets......... $ 160,837 $ 160,837
============= =============
The table above excludes the value of interest rate and currency derivative
instruments.
The table below reflects the impact of the Company's derivative instruments
on its pre-tax earnings, both from cash flow hedge ineffectiveness and from
unrealized mark-to-market activity of derivatives not designated as hedges of
cash flows, for the three and nine months ended September 30, 2003 and 2002,
respectively (in thousands):
Three Months Ended September 30,
------------------------------------------------------------------------------------
2003 2002
------------------------------------------- ----------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
-------------- ------------ ---------- --------------- ----------- ----------
Natural gas derivatives (1).. $ (4,370) $ 10,562 $ 6,192 $ (2,141) $ (19,874) $ (22,015)
Power derivatives (1)........ (115) (17,007) (17,122) (3,072) 14,130 11,058
Interest rate derivatives (2) (262) -- (262) (236) -- (236)
--------- ----------- ----------- --------- --------- ----------
Total..................... $ (4,747) $ (6,445) $ (11,192) $ (5,449) $ (5,744) $ (11,193)
========= =========== =========== ========= ========= ==========
-25-
Nine Months Ended September 30,
------------------------------------------------------------------------------------
2003 2002
------------------------------------------- ----------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
-------------- ------------ ---------- --------------- ----------- ----------
Natural gas derivatives (1).. $ 3,810 $ 12,140 $ 15,950 $ 3,623 $ (30,902) $ (27,279)
Power derivatives (1)........ (4,753) (30,118) (34,871) (4,297) 25,410 21,113
Interest rate derivatives (2) (746) -- (746) (577) -- (577)
--------- ----------- ----------- --------- --------- ----------
Total..................... $ (1,689) $ (17,978) $ (19,667) $ (1,251) $ (5,492) $ (6,743)
========= =========== =========== ========= ========= ==========
- ------------
(1) Recorded within mark-to-market activities, net: unrealized gain (loss) on
power and gas transactions, net
(2) Recorded within Other Income
The table below reflects the contribution of the Company's cash flow hedge
activity to pre-tax earnings (losses) based on the reclassification adjustment
from OCI to earnings for the three and nine months ended September 30, 2003 and
2002, respectively (in thousands):
Three Months Ended September 30,
--------------------------------
2003 2002
------------ ------------
Natural gas and crude oil derivatives.......... $ (127) $ (43,223)
Power derivatives.............................. (30,710) 90,747
Interest rate derivatives...................... (4,166) (3,260)
Foreign currency derivatives................... (740) (10,601)
----------- -----------
Total derivatives........................... $ (35,743) $ 33,663
=========== ===========
Nine Months Ended September 30,
--------------------------------
2003 2002
------------ ------------
Natural gas and crude oil derivatives.......... $ 32,037 $ (118,267)
Power derivatives.............................. (86,260) 252,527
Interest rate derivatives...................... (18,259) (7,734)
Foreign currency derivatives................... 11,089 4,552
----------- -----------
Total derivatives........................... $ (61,393) $ 131,078
=========== ===========
As of September 30, 2003, 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 1/4 and 11 1/4 years, for commodity and interest rate
derivative instruments, respectively. The Company estimates that pre-tax losses
of $69.6 million would be reclassified from accumulated OCI into earnings during
the twelve months ended September 30, 2004, 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.
-26-
2008
2003 2004 2005 2006 2007 & After Total
---------- ----------- ----------- ----------- ----------- ----------- -----------
Crude oil OCI........... $ (518) $ -- $ -- $ -- $ -- $ -- $ (518)
Gas OCI (1)............. 7,927 (1,697) (41,931) 7,004 482 1,197 (27,018)
Power OCI (2)........... 19,138 (27,228) (37,786) (28,338) (1,206) 1,392 (74,028)
Interest rates OCI...... (6,366) (23,045) (17,733) (12,608) (9,274) (36,319) (105,345)
Foreign currency OCI.... (470) (1,908) (1,941) (1,963) (1,587) (86) (7,955)
--------- ---------- ---------- ---------- ---------- ---------- ----------
Total OCI............ $ 19,711 $ (53,878) $ (99,391) $ (35,905) $ (11,585) $ (33,816) $ (214,864)
========= ========== ========== ========== ========== ========== ==========
- ----------
(1) Includes fourth quarter 2003 losses from Enron terminated hedges of $49.7
million.
(2) Includes fourth quarter 2003 gains from Enron terminated hedges of $11.2
million.
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), unrealized gains and losses from derivative instruments that qualify as
hedges, and unrealized gains and losses resulting from the translation of the
Company's foreign currency-denominated financial statements into U.S. dollars.
The Company reports accumulated other comprehensive loss in its Consolidated
Condensed Balance Sheets. 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):
Comprehensive
Total Income (Loss)
Accumulated for the Three
Other Months Ended
Foreign Comprehensive March 31, 2003,
Cash Flow Currency Income June 30, 2003, and
Hedges Translation (Loss) September 30, 2003
------------- ----------- ------------- ------------------
Accumulated other comprehensive loss at January 1, 2003.. $ (224,414) $ (13,043) $ (237,457)
Net loss for the three months ended March 31, 2003....... $ (52,016)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the
three months ended March 31, 2003................ 27,827
Reclassification adjustment for loss included in
net loss for the three months ended
March 31, 2003................................... 14,249
Income tax provision for the three months ended
March 31, 2003................................... (10,927)
------------ ------------ -----------
31,149 31,149 31,149
Foreign currency translation gain for the three
months ended March 31, 2003...................... 84,062 84,062 84,062
------------ ---------- ------------ -----------
Total comprehensive income for the three months ended
March 31, 2003......................................... $ 63,195
-----------
Accumulated other comprehensive income (loss) at
March 31, 2003......................................... $ (193,265) $ 71,019 $ (122,246)
============ ========== ============
Net loss for the three months ended June 30, 2003........ $ (23,366)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the
three months ended June 30, 2003................. $ 47,892
Reclassification adjustment for loss included in
net loss for the three months ended
June 30, 2003.................................... 11,401
Income tax provision for the three months ended
June 30, 2003.................................... (28,790)
------------ ------------
30,503 30,503 30,503
Foreign currency translation gain for the three
months ended June 30, 2003....................... 63,494 63,494 63,494
------------ ---------- ------------ -----------
-27-
Comprehensive
Total Income (Loss)
Accumulated for the Three
Other Months Ended
Foreign Comprehensive March 31, 2003,
Cash Flow Currency Income June 30, 2003, and
Hedges Translation (Loss) September 30, 2003
------------- ----------- ------------- ------------------
Total comprehensive income for the three months ended
June 30, 2003.......................................... $ 70,631
-----------
Total comprehensive income for the six months ended
June 30, 2003.......................................... $ 133,826
===========
Accumulated other comprehensive income (loss) at June
30, 2003............................................... $ (162,762) $ 134,513 $ (28,249)
============ ========== ============
Net income for the three months ended September 30, 2003. $ 237,782
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the
three months ended September 30, 2003............ 17,732
Reclassification adjustment for loss included in
net income for the three months ended
September 30, 2003............................... 35,743
Income tax provision for the three months ended
September 30, 2003............................... (20,100)
------------ ------------
33,375 33,375 33,375
Foreign currency translation loss for the three
months ended September 30, 2003.................. (2,044) (2,044) (2,044)
------------ ---------- ------------ ------------
Total comprehensive income for the three months ended
September 30, 2003..................................... $ 269,113
===========
Total comprehensive income for the nine months ended
September 30, 2003..................................... $ 402,939
===========
Accumulated other comprehensive income (loss)
at September 30, 2003.................................. $ (129,387) $ 132,469 $ 3,082
============ ========== ============
Comprehensive
Total Income (Loss)
Accumulated for the Three
Other Months Ended
Foreign Comprehensive March 31, 2002,
Cash Flow Currency Income June 30, 2002, and
Hedges Translation (Loss) September 30, 2002
------------- ----------- ------------- ------------------
Accumulated other comprehensive loss at January 1, 2002.. $ (180,819) $ (60,061) $ (240,880)
Net loss for the three months ended March 31, 2002....... $ (75,673)
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the
three months ended March 31, 2002................ 130,436
Reclassification adjustment for gain included in
net loss for the three months ended
March 31, 2002................................... (48,490)
Income tax provision for the three months ended
March 31, 2002................................... (32,034)
------------ ------------
49,912 49,912 49,912
Foreign currency translation loss for the three
months ended March 31, 2002...................... (25,171) (25,171) (25,171)
------------ ---------- ------------ -----------
Total comprehensive loss for the three months ended
March 31, 2002......................................... $ (50,932)
===========
Accumulated other comprehensive loss at March 31, 2002... $ (130,907) $ (85,232) $ (216,139)
============ ========== ============
-28-
Comprehensive
Total Income (Loss)
Accumulated for the Three
Other Months Ended
Foreign Comprehensive March 31, 2002,
Cash Flow Currency Income June 30, 2002, and
Hedges Translation (Loss) September 30, 2002
------------- ----------- ------------- ------------------
Net income for the three months ended June 30, 2002...... $ 68,321
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment during the
three months ended June 30, 2002................. $ 49,035
Reclassification adjustment for gain included in
net income for the three months ended
June 30, 2002.................................... (48,925)
Income tax benefit for the three months ended
June 30, 2002.................................... 9,490
------------ ------------
9,600 9,600 9,600
Foreign currency translation gain for the three
months ended June 30, 2002....................... 78,776 78,776 78,776
------------ ---------- ------------ -------------
Total comprehensive income for the three months ended
June 30, 2002.......................................... $ 156,697
-----------
Total comprehensive income for the six months ended
June 30, 2002.......................................... $ 105,765
===========
Accumulated other comprehensive loss at June 30, 2002.... $ (121,307) $ (6,456) $ (127,763)
============ ========== ============
Net income for the three months ended September 30, 2002. $ 151,128
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment during the
three months ended September 30, 2002............ $ (77,958)
Reclassification adjustment for gain included in
net income for the three months ended
September 30, 2002............................... (33,663)
Income tax benefit for the three months ended
September 30, 2002............................... 32,448
------------ ------------
(79,173) (79,173) (79,173)
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..................................... $ 34,466
-----------
Total comprehensive income for the six months ended
September 30, 2002..................................... $ 140,231
===========
Accumulated other comprehensive loss at
September 30, 2002..................................... $ (200,480) $ (43,945) $ (244,425)
============ ========== ============
10. Counterparties and Customers
The Company's customer and supplier base is concentrated within the energy
industry. As a result, the Company has exposure to trends within the energy
industry, including declines in the creditworthiness of its counterparties.
Currently, multiple companies within the energy industry are in bankruptcy or
have below investment grade credit ratings. The Company has exposure to two
counterparties, NRG Power Marketing, Inc. ("NRG") and Mirant Americas Energy
Marketing, L.P. ("Mirant"), which have filed for bankruptcy. Additionally, the
Company has exposure to Aquila, Inc. and its affiliate, Aquila Merchant
Services, Inc. (collectively "Aquila") and Williams Energy Marketing & Trading
Company ("Williams"), which are rated less than investment grade by the credit
rating agencies. The Company believes that its credit exposure to other
companies in the energy industry is not significant either by individual company
or in the aggregate. The table below shows our exposure to the two bankrupt
companies, NRG and Mirant, as well as the two largest exposures to below
investment grade companies, Aquila and Williams, at September 30, 2003 (in
thousands):
-29-
Net Accounts
Net Receivable
Derivative and Letters of Credit,
Assets and Accounts Margin or Other
Liabilities Payable Reserve Offsets Net Exposure
------------ ------------ ------------- ------------------ -------------
NRG................... $ 431 $ 12,867 $ (3,162) $ -- $ 10,136
Mirant................ $ 3,291 $ 2,373 $ (472) $ (750) $ 4,442
Aquila................ $ 41,008 $ (551) $ (2,416) $ (24,910) (1) $ 13,131
Williams.............. $ 6,009 $ (17,745) $ (416) $ 3,240 (2) $ (8,912)
- ------------
(1) Margin deposit held by the Company on its balance sheet classified as other
current liabilities
(2) Margin deposits held by Williams.
On May 14, 2003, NRG Energy, Inc. ("NRG") and several affiliates filed
chapter 11 bankruptcy petitions in the United States Bankruptcy Court for the
Southern District of New York. Calpine has filed proofs of claim in the NRG
bankruptcy for certain contingent, unliquidated amounts, and pre-bankruptcy
petition and post-bankruptcy petition delivery of electric energy by Calpine to
NRG for April and the first half of May 2003. At September 30, 2003, the Company
had approximately $10.1 million in net exposure.
On July 14, 2003, Mirant Americas Energy Marketing, L.P. ("Mirant") and
several affiliates filed chapter 11 bankruptcy petitions in the United States
Bankruptcy Court for the Northern District of Texas. Pursuant to an order
entered by the bankruptcy court on July 15, 2003, Mirant has timely made all
payments under the Master Power Purchase and Sale Agreement between the parties
(the "Master Agreement"), on both pre- and post-petition obligations. The
Company has also executed a post-petition assurance agreement (the "Assurance
Agreement") with Mirant, covering continued performance of Mirant's
post-petition obligations on its contracts with Calpine. Mirant's motion for
approval of the Assurance Agreement and the assumption of the Master Agreement
was granted by the bankruptcy court on August 27, 2003; therefore, Mirant will
be required to continue to timely pay all post-petition obligations under the
Master Agreement. Additionally, the post-petition assurance agreement provides
certain other protections to Calpine. Calpine's current post-petition exposure
to Mirant as of September 30, 2003, is $4.4 million, and Calpine has no
pre-petition exposure to Mirant.
Enron Corporation, and a number of its subsidiaries and affiliates
(including Enron North America Corp. ("ENA") and Enron Power Marketing, Inc.
("EPMI")) (collectively "Enron Bankrupt Entities") filed for Chapter 11
bankruptcy protection on December 2, 2001. At the time of the filing, CES was a
party to various open energy derivatives, swaps, and forward power and gas
transactions stemming from agreements with ENA and EPMI. On November 14, 2001,
CES, ENA, and EPMI entered into a Master Netting Agreement, which granted the
parties a contractual right to setoff amounts owed between them pursuant to the
above agreements. The above agreements were terminated by CES on December 10,
2001. The Master Netting Agreement however remained in place. In October 2002
Calpine and various affiliates filed proofs of claim against the Enron Bankrupt
Entities.
Calpine and Enron reached a final settlement agreement with regard to the
Company's terminated trading positions with Enron. The agreement was approved by
the Unsecured Creditors' committee on July 24, 2003, and by the Bankruptcy Court
on August 7, 2003. The settlement is now final. Under the terms of the
settlement agreement, CES will make five monthly installment payments of $19.4
million beginning August 22, 2003, and ending December 22, 2003. The nominal
total of the payments to Enron will be $97.0 million ($95.7 million on a
discounted basis). Once final payment is made, all claims between the parties
relating to these matters will be released and extinguished.
In connection with this settlement, the Company recorded other revenue of
$69.4 million related to settlement of net liabilities associated with
terminated derivative positions and receivables and payables with Enron
Corporation, and a number of its subsidiaries and affiliates. Prior to reaching
final settlement Calpine had recorded a net liability to Enron relating to these
transactions. The ultimate obligation to Enron based upon the terms of the final
negotiated settlement agreement was less than the net liability Calpine had
previously recorded. Calpine recorded the difference as other revenue. The
reduction to the previously recorded net liability was the result of giving
economic recognition in the settlement to value associated with: 1) commodity
contracts that were not given accounting recognition (i.e. in-the-money
commodity contracts accounted for as normal purchases and sales), 2) forgiveness
of liabilities due to differences in discounting assumptions, and 3) claims
recoveries.
-30-
A significant portion of the liability to Enron related to commodity
derivatives that had been designated as hedges of price risk associated with
Calpine's natural gas consumption, and to a lesser degree, its electric power
generation. Under the hedge accounting rules, losses associated with designated
hedges are recorded in a company's balance sheet and recognized into earnings
when the transactions being hedged occur even if the hedge instruments are
terminated prior to the occurrence of the hedged transactions. As of September
30, 2003 Calpine has reclassified losses of approximately $150.8 million into
income related to 2003 transactions hedged by Enron derivatives. Most of these
losses were recorded as fuel expense consistent with Calpine's policy for
classifying gains and losses on designated fuel hedges. Because of the character
of the transactions giving rise to the Enron liability, Calpine classified the
settlement as other revenue.
11. Earnings per Share
Basic earnings per common share ("EPS") 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 income per common share to diluted
income per common share is shown in the following table (in thousands, except
per share data).
Periods Ended September 30,
-----------------------------------------------------------------
2003 2002
-------------------------------- -------------------------------
Net Weighted Weighted
Income Average Net Average
(Loss) Shares EPS Income Shares EPS
----------- -------- ------- ----------- -------- -------
THREE MONTHS:
Basic earnings per common share:
Income before discontinued operations............... $ 238,909 388,161 $ 0.62 $ 141,867 376,957 $ 0.38
Discontinued operations, net of tax................. (1,127) -- (0.01) 9,261 -- 0.02
----------- -------- ------- ----------- -------- -------
Net income.......................................... $ 237,782 388,161 $ 0.61 $ 151,128 376,957 $ 0.40
=========== ======== ======= =========== ======== =======
Diluted earnings per common share:
Common shares issuable upon exercise of stock
options using treasury stock method............... 6,789 5,650
-------- --------
Income before dilutive effect of certain convertible
securities, discontinued operations
and cumulative effect of a change in
accounting principle.............................. $ 238,909 394,950 $ 0.60 $ 141,867 382,607 $ 0.37
Dilutive effect of certain convertible securities... 17,788 106,844 (0.09) 14,326 99,377 (0.05)
Income before discontinued operations
and cumulative effect of a change in
accounting principle.............................. 256,697 501,794 0.51 156,193 481,984 0.32
Discontinued operations, net of tax................. (1,127) -- -- 9,261 -- 0.02
Cumulative effect of a change in accounting
principle, net of tax............................. -- -- -- -- -- --
----------- -------- ------- ----------- -------- -------
Net income.......................................... $ 255,570 501,794 $ 0.51 $ 165,454 481,984 $ 0.34
=========== ======== ======= =========== ======== =======
Periods Ended September 30,
-----------------------------------------------------------------
2003 2002
-------------------------------- -------------------------------
Net Weighted Weighted
Income Average Net Average
(Loss) Shares EPS Income Shares EPS
----------- -------- ------- ----------- -------- -------
NINE MONTHS:
Basic earnings per common share:
Income before discontinued operations............... $ 173,142 383,447 $ 0.45 $ 123,576 346,816 $ 0.36
Discontinued operations, net of tax................. (11,271) -- (0.03) 20,200 -- 0.05
Cumulative effect of a change in accounting
principle, net of tax............................. 529 -- -- -- -- --
----------- -------- ------- ----------- -------- -------
Net income.......................................... $ 162,400 383,447 $ 0.42 $ 143,776 346,816 $ 0.41
=========== ======== ======= =========== ======== =======
-31-
Periods Ended September 30,
-----------------------------------------------------------------
2003 2002
-------------------------------- -------------------------------
Net Weighted Weighted
Income Average Net Average
(Loss) Shares EPS Income Shares EPS
----------- -------- ------- ----------- -------- -------
Diluted earnings per common share:
Common shares issuable exercise of stock
options using treasury stock method............... 5,175 8,761
-------- --------
Income before dilutive effect of certain convertible
securities, discontinued operations
and cumulative effect of a change in
accounting principle.............................. $ 173,142 388,622 $ 0.45 $ 123,576 355,577 $ 0.35
Dilutive effect of certain convertible securities... 32,368 83,607 (0.01) -- -- --
Income before discontinued operations
and cumulative effect of a change in
accounting principle.............................. 205,510 472,229 0.44 123,576 355,577 0.35
Discontinued operations, net of tax................. (11,271) -- (0.03) 20,200 -- 0.05
Cumulative effect of a change in accounting
principle, net of tax............................. 529 -- -- -- -- --
----------- -------- ------- ----------- -------- -------
Net income.......................................... $ 194,768 472,229 $ 0.41 $ 143,776 355,577 $ 0.40
=========== ======== ======= =========== ======== =======
Potentially convertible securities and unexercised employee stock options
to purchase 12.5 million, 42.0 million, 28.1 million, and 124.8 million shares
of the Company's common stock were not included in the computation of diluted
shares outstanding during the three and nine months ended September 30, 2003 and
2002, respectively, because such inclusion would be anti-dilutive.
12. Commitments and Contingencies
Capital Expenditures - On February 11, 2003, the Company announced a
significant restructuring of its turbine agreements which has enabled the
Company to cancel up to 131 steam and gas turbines. The Company recorded a
pre-tax charge of $207.4 million in the quarter ending December 31, 2002, in
connection with fees paid to vendors to restructure these contracts. To date 57
of these turbines have been cancelled, leaving the disposition of 74 turbines
still to be determined.
In July 2003, the Company completed a restructuring of its existing
agreements for 20 gas and 2 steam turbines. The new agreement provides for later
payment dates, which are in line with the Company's construction program. The
table below sets forth future turbine payments for construction and development
projects, as well as for unassigned turbines. It includes previously delivered
turbines, payments and delivery year for the remaining 10 turbines to be
delivered as well as payment required for the potential cancellation costs of
the remaining 74 gas and steam turbines. The table does not include payments
that would result if the Company were to release for manufacturing any of these
remaining 74 turbines.
Year Total (in thousands) Units To Be Delivered
- ------------------- --------------------- ---------------------
2003............... $ 56,963 2
2004............... 143,935 8
2005............... 17,737 -
2006............... 2,516 -
------------ --
Total.............. $ 221,151 10
============ ==
Litigation - The Company is party to various litigation matters arising out
of the normal course of business, the more significant of which are summarized
below. The ultimate outcome of each of these matters cannot presently be
determined, nor can the liability that could potentially result from a negative
outcome be reasonably estimated presently for every case. The liability the
Company may ultimately incur with respect to any one of these matters in the
event of a negative outcome may be in excess of amounts currently accrued with
respect to such matters and, as a result, these matters may potentially be
material to the Company's Consolidated Condensed Financial Statements.
Securities Class Action Lawsuits. Since March 11, 2002, fourteen
shareholder lawsuits have been filed against the Company and certain of its
officers in the United States District Court, Northern District of California.
The actions captioned Weisz vs. 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
-32-
between February 6, 2001 and December 13, 2001. The eleven other actions,
captioned Local 144 Nursing Home Pension Fund vs. Calpine Corp., Lukowski vs.
Calpine Corp., Hart vs. Calpine Corp., Atchison vs. Calpine Corp., Laborers
Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp.
Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp, and
Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The
complaints in these eleven actions are virtually identical - they are filed by
three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of 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 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.
In addition, a fifteenth securities class action, Ser v. Calpine, et al.,
was filed on May 13, 2002. The underlying allegations in the Ser action are
substantially the same as those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of Calpine's
8.5% Senior Notes due February 15, 2011 ("2011 Notes") and the alleged class
period is October 15, 2001 through December 13, 2001. The Ser complaint alleges
that, in violation of Sections 11 and 15 of the Securities Act of 1933, the
Supplemental Prospectus for the 2011 Notes contained false and misleading
statements regarding the Company's financial condition. This action names the
Company, certain of its officers and directors, and the underwriters of the 2011
Notes offering as defendants, and seeks an unspecified amount of damages, in
addition to other forms of relief.
All fifteen of these securities class action lawsuits were consolidated in
the U.S. District Court for the Northern District Court of California. The
plaintiffs filed a first amended complaint in October 2002. The amended
complaint did not include the 1933 Act complaints raised in the bondholders'
complaint, and the number of defendants named was reduced. On January 16, 2003,
before our response was due to this amended complaint, the plaintiffs filed a
further second complaint. This second amended complaint added three additional
Calpine executives and Arthur Andersen LLP as defendants. The second amended
complaint set forth additional alleged violations of Section 10 of the
Securities Exchange Act of 1934 relating to allegedly false and misleading
statements made regarding Calpine's role in the California energy crisis, the
long term power contracts with the California Department of Water Resources, and
Calpine's dealings with Enron, and additional claims under Section 11 and
Section 15 of the Securities Act of 1933 relating to statements regarding the
causes of the California energy crisis. We filed a motion to dismiss this
consolidated action in early April 2003.
On August 29, 2003, the judge issued an order dismissing, with leave to
amend, all of the allegations set forth in the second amended complaint except
for a claim under Section 11 of the Securities Act relating to statements
relating to the causes of the California energy crisis and the related increase
in wholesale prices contained in the Supplemental Prospectuses for the 2011
Notes. The judge instructed plaintiffs to file a third amended complaint, which
they did on October 20, 2003. The third amended complaint names Calpine and
three executives as defendants and alleges the Section 11 claim that survived
the judges August 29, 2003 order. We consider the lawsuit to be without merit
and we intend to defend vigorously against these allegations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities
class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was
filed on March 11, 2003, against Calpine, its directors and certain investment
banks in the California Superior Court, San Diego County. The underlying
allegations in the Hawaii Structural Ironworkers Pension Fund action ("Hawaii
action") are substantially the same as the federal securities class actions
described above. However, the Hawaii action is brought on behalf of a purported
class of purchasers of the Company's equity securities sold to public investors
in its April 2002 equity offering. The Hawaii action alleges that the
Registration Statement and Prospectus filed by Calpine which became effective on
April 24, 2002, contained false and misleading statements regarding the
Company's financial condition in violation of Sections 11, 12 and 15 of the
Securities Act of 1933. The Hawaii action relies in part on the Company's
restatement of certain past financial results, announced on March 3, 2003, to
support its allegations. The Hawaii action seeks an unspecified amount of
damages, in addition to other forms of relief. The Company removed the Hawaii
action to federal court in April 2003 and filed a motion to transfer the case
for consolidation with the other securities class action lawsuits in the U.S.
District Court Northern District Court of California in May 2003. The plaintiff
has sought to have the action remanded to state court. On August 27, 2003, the
U.S. District Court for the Southern District of California granted plaintiff's
motion to remand the action to state court. In early October 2003 plaintiff
agreed to dismiss the claims it has against three of the outside directors. On
November 5, 2003, Calpine filed a motion to dismiss this complaint. The Company
considers this lawsuit to be without merit and intends to defend vigorously
against it.
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Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in
the Calpine Corporation Retirement Savings Plan (the "401(k) Plan") filed a
class action lawsuit in the Northern District Court of California. The
underlying allegations in this action ("Phelps action") are substantially the
same as those in the securities class actions described above. However, the
Phelps action is brought on behalf of a purported class of participants in the
401(k) Plan. The Phelps action alleges that various filings and statements made
by Calpine during the class period were materially false and misleading, and
that the defendants failed to fulfill their fiduciary obligations as fiduciaries
of the 401(k) Plan by allowing the 401(k) Plan to invest in Calpine common
stock. The Phelps action seeks an unspecified amount of damages, in addition to
other forms of Shareholder relief. In May 2003 Lennette Poor-Herena, another
participant in the 401(k) Plan, filed a substantially similar class action
lawsuit as the Phelps action also in the Northern District of California.
Plaintiffs' counsel is the same in both of these actions, and they have agreed
to consolidate these two cases and to coordinate them with the consolidated
federal securities class actions described above. The Company considers these
lawsuits to be without merit and intends to vigorously defend against them.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of the Company against its directors and
one if its senior officers. This lawsuit is captioned Johnson v. Cartwright, et
al. 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 Calpine and stock sales by certain of
the director defendants and the officer defendant. In December 2002 the court
dismissed the complaint with respect to certain of the director defendants for
lack of personal jurisdiction, though the plaintiff may appeal this ruling. In
early February 2003 the plaintiff filed an amended complaint. In March 2003 the
Company and the individual defendants filed motions to dismiss and motions to
stay this proceeding in favor of the federal securities class actions described
above. In July 2003 the Court granted the motions to stay this proceeding in
favor of the federal securities class actions. The Company considers this
lawsuit to be without merit and intends to vigorously defend against it.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District
California on behalf of Calpine against its directors, captioned Gordon v.
Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003 plaintiff agreed to stay these proceedings in
favor of the consolidated federal securities class actions described above and
to dismiss without prejudice certain director defendants. On March 4, 2003, the
plaintiff filed papers with the court voluntarily agreeing to dismiss without
prejudice the claims he had against three of the outside directors. We consider
this lawsuit to be without merit and intend to continue to defend vigorously
against it.
Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, 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"). Calpine wrote off $17.7 million in December 2001 related
to losses that it alleged were caused by ACE. Calpine and ACE entered into a
settlement agreement on March 29, 2002, pursuant to which ACE made a payment to
the Company of $7 million and transferred to the Company the rights to the
emission reduction credits to be held by ACE. The Company recognized the $7
million as income in the second quarter of 2002. In June 2002 a complaint was
filed by InterGen North America, L.P. ("InterGen") against Anne M. Sholtz, the
owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for
bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of
emission reduction credits from EonXchange in a manner similar to 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. Ann Sholtz
recently stipulated to agree to the consolidation of Anne Sholtz, ACE and other
Sholtz entities in the EonXchange bankruptcy proceeding. On July 10, 2003,
Howard Grobstein, the Trustee in the EonXchange bankruptcy, filed a complaint
for avoidance against Calpine, seeking recovery of the $7 million (plus interest
and costs) paid to Calpine in the March 29, 2002 Settlement Agreement. The
complaint claims that the $7 million received by Calpine in the Settlement
Agreement was transferred within 90 days of the filing of bankruptcy and
therefore should be avoided and preserved for the benefit of the bankruptcy
estate. On August 28, 2003, Calpine filed its answer denying that the $7 million
is an avoidable preference. Discovery is currently ongoing. Calpine believes
that it has valid defenses to this claim and will vigorously defend against this
complaint.
International Paper Company v. Androscoggin Energy LLC. In October 2000
International Paper Company ("IP") filed a complaint in the Federal District
Court for the Northern District of Illinois against Androscoggin Energy LLC
("AELLC") alleging that AELLC breached certain contractual representations and
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warranties by failing to disclose facts surrounding the termination, effective
May 8, 1998, of one of AELLC's fixed-cost gas supply agreements. The Company had
acquired a 32.3% interest in AELLC as part of the SkyGen transaction which
closed in October 2000. AELLC filed a counterclaim against IP that has been
referred to arbitration. AELLC may commence the arbitration counterclaim after
discovery has progressed further. On November 7, 2002, the court issued an
opinion on the parties' cross motions for summary judgment finding in AELLC's
favor on certain matters though granting summary judgment to IP on the liability
aspect of a particular claim against AELLC. The Court also denied a motion
submitted by IP for preliminary injunction to permit IP to make payment of funds
into escrow (not directly to AELLC) and require AELLC to post a significant
bond. The Court has a set schedule for disclosure of expert witness and
depositions thereof and has tentatively scheduled the case for trial in the
first quarter of 2004.
In mid-April of 2003 IP unilaterally availed itself to self-help in
withholding amounts in excess of $2.0 million as a set-off for litigation
expenses and fees incurred to date as well as an estimated portion of a rate
fund to AELLC. AELLC has submitted an amended complaint and request for
immediate injunctive relief against such actions. The Court heard the motion on
April 24, 2003, and ordered that IP must pay the approximately $1.2 million
withheld as attorneys' fees related to the litigation as any such perceived
entitlement was premature, but deferred to provide injunctive relief on the
incomplete record concerning the offset of $799,000 as an estimated pass-through
of the rate fund. IP complied with the order on April 29, 2003, and tendered
payment to AELLC of the approximately $1.2 million. On June 26, 2003, the court
entered an order dismissing AELLC's Amended Counterclaim without prejudice to
AELLC refiling the claims as breach of contract claims in a separate lawsuit. On
June 30, 2003, AELLC filed a motion to reconsider the order dismissing AELLC's
Amended Counterclaim. On October 7, 2003, IP filed a Motion for Summary Judgment
on certain damages issues. AELLC as well anticipates filing a Motion for Summary
Judgment on certain damages issues forthwith. The case is tentatively scheduled
for trial in the first quarter of 2004. The Company believes it has adequately
reserved for the possible loss, if any, it may ultimately incur as a result of
this matter.
Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22,
2003, Pacific Gas and Electric Company ("PG&E") filed with the California Public
Utilities Commission ("CPUC") a Complaint of PG&E and Request for Immediate
Issuance of an Order to Show Cause ("Complaint") against Calpine Corporation,
CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas
Company, and Lodi Gas Storage, LLC ("LGS") . The complaint requests the CPUC to
issue an order requiring the defendants to show cause why they should not be
ordered to cease and desist from using any direct interconnections between the
facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek
and obtain regulatory approval from the CPUC. The Complaint also seeks an order
directing defendants to pay to PG&E any underpayments of PG&E's tariffed
transportation rates and to make restitution for any profits earned from any
business activity related to LGS' direct interconnections to any entity other
than PG&E. The Complaint also alleges that various natural gas consumers,
including Company-affiliated generation projects within California, are engaged
with defendants in the acts complained of, and that the defendants unlawfully
bypass PG&E's system and operate as an unregulated local distribution company
within PG&E's service territory. On August 27, 2003, Calpine filed its answer
and a motion to dismiss. LGS has also made similar filings, and Calpine is
contractually obligated to indemnify LGS for certain losses it may suffer as a
result of the Complaint. Calpine has denied the allegations in the Complaint,
believes this Complaint to be without merit and intends to vigorously defend its
position at the CPUC. On October 16, 2003, the presiding administrative law
judge denied the motion to dismiss and on October 24, 2003, issued a Scoping
Memo and Ruling establishing a procedural schedule and setting the evidentiary
hearing to commence on February 17, 2004. Discovery is currently ongoing.
13. Operating Segments
The Company is first and foremost an electric generating company. In
pursuing this single business strategy, it is the Company's objective to produce
at a level of approximately 25% of its fuel consumption requirements from its
own natural gas reserves ("equity gas"). Since the Company's oil and gas
production and marketing activity has reached the quantitative criteria to be
considered a reportable segment under SFAS No. 131, "Disclosures about Segments
of an Enterprise and Related Information," the following represents reportable
segments and their defining criteria. The Company's segments are electric
generation and marketing; oil and gas production and marketing; and corporate
and other activities. Electric generation and marketing includes the
development, acquisition, ownership and operation of power production
facilities, hedging, balancing, optimization, and trading activity transacted on
behalf of the Company's power generation facilities. Oil and gas production
includes the ownership and operation of gas fields, gathering systems and gas
pipelines for internal gas consumption, third party sales and hedging,
balancing, optimization, and trading activity transacted on behalf of the
Company's oil and gas operations. Corporate activities and other consists
primarily of financing activities and general and administrative costs. Certain
costs related to company-wide functions are allocated to each segment, such as
interest expense, distributions on HIGH TIDES, and interest income, which are
allocated based on a ratio of segment assets to total assets.
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The Company evaluates performance based upon several criteria including
profits before tax. The financial results for the Company's operating segments
have been prepared on a basis consistent with the manner in which the Company's
management internally disaggregates financial information for the purposes of
assisting in making internal operating decisions.
Due to the integrated nature of the business segments, estimates and
judgments have been made in allocating certain revenue and expense items, and
reclassifications have been made to prior periods to present the allocation
consistently.
Electric Oil and Gas
Generation Production
and Marketing and Marketing Corporate and Other Total
---------------------- ---------------------- ---------------------- ---------------------
2003 2002 2003 2002 2003 2002 2003 2002
----------- ---------- ----------- ---------- ----------- ---------- ---------- ----------
(In thousands)
For the three months
ended September 30,
Revenue from
external
customers......... $ 2,655,887 $2,452,845 $ 21,661 $ 21,262 $ 9,579 $ 591 $2,687,127 $2,474,698
Intersegment Revenue -- -- 92,820 46,957 -- -- 92,820 46,947
Segment profit
(loss)............ 118,079 171,248 27,009 17,800 135,741 1,205 280,829 190,253
Equipment
cancellation and
impairment cost... 632 10,884 -- -- -- -- 632 10,884
Electric Oil and Gas
Generation Production
and Marketing and Marketing Corporate and Other Total
---------------------- ---------------------- ---------------------- ---------------------
2003 2002 2003 2002 2003 2002 2003 2002
----------- ---------- ----------- ---------- ----------- ---------- ---------- ----------
(In thousands)
For the nine months
ended September 30,
Revenue from
external
customers......... $ 6,966,499 $5,465,386 $ 67,115 $ 95,264 $ 24,083 $ 3,127 $7,057,697 $5,563,777
Intersegment Revenue -- -- 320,529 116,911 -- -- 320,529 116,911
Segment profit
(loss)............ 81,410 228,202 96,107 53,916 17,112 (124,957) 194,629 157,161
Equipment
cancellation and
impairment cost... 19,940 193,555 -- -- -- -- 19,940 193,555
Corporate,
Electric Oil and Gas Other
Generation Production and
and Marketing and Marketing Eliminations Total
-------------- -------------- ------------ -------------
(In thousands)
Total assets:
September 30, 2003............. $ 23,170,006 $ 1,741,134 $ 1,125,322 $ 26,036,462
December 31, 2002.............. $ 18,587,342 $ 1,713,085 $ 2,926,565 $ 23,226,992
Intersegment revenues primarily relate to the use of internally procured
gas for the Company's power plants. These intersegment revenues have been
eliminated in the oil and gas production and marketing segment revenue, but have
been included in the segment's measure of income before taxes.
14. California Power Market
California Refund Proceeding - On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric
Company and under Section 206 of the Federal Power Act alleging, among other
things, that the markets operated by the California Independent System Operator
("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. In
addition to commencing an inquiry regarding the market structure, FERC
established a refund effective period of October 2, 2000, to June 19, 2001, for
sales made into those markets.
On December 12, 2002, the Administrative Law Judge issued a Certification
of Proposed Finding on California Refund Liability ("December 12 Certification")
making an initial determination of refund liability. On March 26, 2003, FERC
also issued an order adopting many of the ALJ's findings set forth in the
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December 12 Certification (the "March 26 Order"). In addition, as a result of
certain findings by the FERC staff concerning the unreliability or misreporting
of certain reported indices for gas prices in California during the refund
period, FERC ordered that the basis for calculating a party's potential refund
liability be modified by substituting a gas proxy price based upon gas prices in
the producing areas plus the tariff transportation rate for the California gas
price indices previously adopted in the refund proceeding. The Company believes,
based on the available information, that any refund liability that may be
attributable to it will increase modestly, from approximately $6.2 million to
$8.4 million, after taking the appropriate set-offs for outstanding receivables
owed by the CalPX and CAISO to Calpine. The Company has fully reserved the
amount of refund liability that by its analysis would potentially be owed under
the refund calculation clarification in the March 26 order. The final
determination of the refund liability is subject to further Commission
proceedings to ascertain the allocation of payment obligations among the
numerous buyers and sellers in the California markets. At this time, the Company
is unable to predict the timing of the completion of these proceedings or the
final refund liability. The final outcome of this proceeding and the impact on
the Company's business is uncertain at this time.
FERC Investigation into Western Markets - On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western United States. This investigation was initiated as a
result of allegations that Enron and others used their market position to
distort electric and natural gas markets in the West. The scope of the
investigation is to consider whether, as a result of any manipulation in the
short-term markets for electric energy or natural gas or other undue influence
on the wholesale markets by any party since January 1, 2000, the rates of the
long-term contracts subsequently entered into in the West are potentially unjust
and unreasonable. FERC has stated that it may use the information gathered in
connection with the investigation to determine how to proceed on any existing or
future complaint brought under Section 206 of the Federal Power Act involving
long-term power contracts entered into in the West since January 1, 2000, or to
initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding
on its own initiative. On August 13, 2002, the FERC staff issued the Initial
Report on Company-Specific Separate Proceedings and Generic Reevaluations;
Published Natural Gas Price Data; and Enron Trading Strategies (the "Initial
Report") summarizing its initial findings in this investigation. There were no
findings or allegations of wrongdoing by Calpine set forth or described in the
Initial Report. On March 26, 2003, the FERC staff issued a final report in this
investigation (the "Final Report"). The FERC staff recommended that FERC issue a
show cause order to a number of companies, including Calpine, regarding certain
power scheduling practices that may potentially be in violation of the CAISO's
or CalPX' tariff. The Final Report also recommended that FERC modify the basis
for determining potential liability in the California Refund Proceeding
discussed above. Calpine believes that it did not violate these tariffs and
that, to the extent that such a finding could be made, any potential liability
would not be material. On June 25, 2003, FERC rejected various complaints to
invalidate certain long-term energy supply contracts.
Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject Calpine to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per megawatt hour into markets operated by either the
CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may
have violated CAISO and CalPX tariff prohibitions. No individual market
participant was identified. The Company believes that it did not violate the
CAISO and CalPX tariff prohibitions referred to by FERC in this order; however,
we are unable to predict at this time the final outcome of this proceeding or
its impact on Calpine.
15. Subsequent Events
On October 6, 2003, Calpine Power Income Fund ("CPIF") obtained a $120.0
million extendible revolving term credit facility through Calpine Commercial
Trust. This facility is split into two tranches and has a three-year term,
comprised of a two-year revolving period followed by a one-year term period. One
tranche of $90.0 million is available only to finance strategic acquisitions,
with the remaining $30.0 million tranche available to CPIF for acquisitions as
well as for general corporate purposes.
On October 15, 2003, the Company closed the initial public offering of
Calpine Natural Gas Trust ("CNG Trust"). A total of 18,454,200 trust units were
issued at a price of Cdn$10.00 per trust unit for gross proceeds of
approximately Cdn$184.5 million (US$139.4 million). CNG Trust acquired select
natural gas and petroleum properties from Calpine with the proceeds from the
initial public offering, Cdn$61.5 million (US$46.5 million) proceeds from a
concurrent issuance of units to a Canadian affiliate of Calpine, and Cdn$40.0
million (US$30.2 million) from bank debt. Net proceeds to Calpine, totaling
approximately Cdn$207.9 million (US$157.1 million), will be used for general
corporate purposes (all conversions to U.S. dollars based on using an exchange
rate of Cdn$1.0 to US$0.7556 as of October 15, 2003). Calpine holds 25 percent
of the outstanding trust units of CNG Trust and will participate, by way of
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investment, in the future business strategy of the trust. The Company will also
have the option to purchase up to 100% of CNG Trust's ongoing natural gas and
petroleum production.
On October 20, 2003, Moody's downgraded the rating of the Company's
long-term senior unsecured debt from B1 to Caa1 (with a stable outlook) and our
senior implied rating from Ba3 to B2 (with a stable outlook). The ratings on the
Company's senior unsecured debt, senior unsecured convertible debt and
convertible preferred securities were also lowered (with a stable outlook). The
Moody's downgrade does not impact the Company's credit agreements, and the
Company continues to conduct its business with its usual creditworthy
counterparties.
On October 21, 2003, the syndicate of underwriters fully exercised the
over-allotment option that was granted as part of the initial public offering of
the CNG Trust. Concurrently, a Canadian affiliate of Calpine maintained its 25 %
ownership in CNG Trust by fully exercising its option to acquire 615,140 trust
units at Cdn$10.00 per trust unit for cash of approximately Cdn$6.2 million
(US$4.7 million) (all conversions to U.S. dollars based on using an exchange
rate of Cdn$1.0 to US$0.7579 as of October 21, 2003).
On November 6, 2003, the Company priced its separate offerings of senior
unsecured convertible notes and second priority senior secured notes. The
offering includes $400 million of 9.875% Second Priority Senior Secured Notes
due 2011, offered at 98.01% of par. This offering is expected to close on
November 18, 2003. The Company expects to use the net proceeds from this
offering to purchase outstanding senior notes. The other offering includes $600
million of 4.75% Senior Unsecured Convertible Notes due 2023. The securities
will be convertible into cash and into shares of Calpine common stock at a price
of $6.50 per share, which represents a 38% premium on the November 6, 2003 New
York Stock Exchange closing price of $4.71 per Calpine common share. In
addition, the Company has granted the initial purchaser an option to purchase an
additional $300 million of the senior unsecured convertible notes. This offering
is expected to close on November 14, 2003. Net proceeds from this offering will
be used to repurchase existing indebtedness.
On November 7, 2003, S&P's Ratings Services assigned a `B' rating to the
Company's planned $400.0 million second priority senior secured notes and a
'CCC+' rating to the Company's planned $600.0 million senior unsecured
convertible notes (both with negative outlook).
On November 7, 2003, the Company completed a $140 million, 15-year,
non-recourse term loan for its Blue Spruce Energy Center. Funds from this new
term loan were used to repay the outstanding balance under its $106 million
non-recourse construction financing for this facility.
Senior Notes repurchased by the Company subsequent to September 30, 2003,
have totaled approximately $11.7 million in aggregate outstanding principal
amount at a cost of approximately $8.3 million plus accrued interest to the
settlement dates. The Company expects to record a pre-tax gain on these
transactions in the amount of $3.2 million, net of write-offs of the associated
unamortized deferred financing costs and unamortized premiums or discounts.
Convertible Senior Notes due 2006 of approximately $25.0 million in
aggregate outstanding principal amount were exchanged for 4.8 million shares of
Calpine common stock in privately negotiated transactions subsequent to
September 30, 2003. The Company expects to record a pre-tax gain on these
transactions in the amount of $0.2 million, net of write-offs of the associated
unamortized deferred financing costs and unamortized premiums or discounts.
On November 5, 2003, Panda Energy International, Inc. and certain related
parties (collectively "Panda") filed suit against the Company and certain of its
affiliates alleging, among other things, that the Company breached duties of
care and loyalty allegedly owed to Panda by failing to construct and operate the
Oneta power plant, which the Company acquired from Panda, in accordance with
Panda's original plans. Panda claims to be entitled to a portion of the profits
of the Oneta plant and that the Company's alleged failures have reduced the
profits from the Oneta plant thereby undermining Panda's ability to repay monies
owed to the Company due on December 1, 2003. The Company and Panda have begun
discussions regarding this matter. We consider the lawsuit to be without merit
and intend to defend vigorously against it.
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Item 2. Management's Discussion and Analysis ("MD&A") of Financial Condition and
Results of Operations.
In addition to historical information, this report contains forward-looking
statements. 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, and the impact of related derivatives transactions, (iii)
unscheduled outages of operating plants, (iv) unseasonable weather patterns that
produce reduced demand for power, (v) systemic economic slowdowns, which can
adversely affect consumption of power by businesses and consumers, (vi)
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 project financing on
acceptable terms, (vii) cost estimates are preliminary and actual costs may be
higher than estimated, (viii) a competitor's development of lower-cost power
plants or of a lower cost means of operating a fleet of power plants, (ix) risks
associated with marketing and selling power from power plants in the evolving
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 legal title, regulatory, gas
administration, marketing and operational factors relating to the extraction of
natural gas, (xi) our estimates of oil and gas reserves may not be accurate,
(xii) the effects on the Company's business resulting from reduced liquidity in
the trading and power generation industry, (xiii) the Company's ability to
access the capital markets on attractive terms or at all, (xiv) sources and uses
of cash are estimates based on current expectations; actual sources may be lower
and actual uses may be higher than estimated, (xv) 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, (xvi) possible
future claims, litigation and enforcement actions pertaining to the foregoing or
(xvii) other risks as identified herein. Current information set forth in this
filing has been updated to November 13, 2003, and Calpine undertakes no duty to
further update this information. All other information in this filing is
presented as of the specific date noted and has not been updated since that
time.
We file annual, quarterly and periodic reports, proxy statements and other
information with the SEC. You may obtain and copy any document we file with the
SEC at the SEC's public reference 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 our SEC filings, at no cost to you, by writing or telephoning us at: Calpine
Corporation, 50 West San Fernando Street, San Jose, California 95113, attention:
Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115. We will
not send exhibits to the documents, unless the exhibits are specifically
requested and you pay our fee for duplication and delivery.
The information contained in this MD&A section reflects the restatements of
the 2002 financial results as discussed in Note 2 of the Notes to the
Consolidated Condensed Financial Statements.
Selected Operating Information
Set forth below is certain selected operating information for our power
plants for which results are consolidated in our Statements of Operations.
Electricity revenue is composed of capacity revenues, which are not related to
production, and variable energy payments, which are related to production.
Capacity revenues include, other revenues such as Reliability Must Run and
Ancillary Service revenues. The information set forth under thermal and other
revenue consists of host steam sales and other thermal revenue.
-39-
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ------------------------------
2003 2002 2003 2002
-------------- -------------- -------------- --------------
Restated (1) Restated (1)
(In thousands, except
production and pricing data)
Power Plants:
Electricity and steam ("E&S") revenue:
Energy........................................... $ 1,028,571 $ 498,679 $ 2,589,226 $ 1,557,574
Capacity......................................... 279,902 402,867 665,182 599,768
Thermal and other................................ 131,583 41,631 380,322 115,547
-------------- -------------- -------------- --------------
Subtotal......................................... $ 1,440,056 $ 943,177 $ 3,634,730 $ 2,272,889
Spread on sales of purchased power (2).............. 7,121 218,679 14,542 476,772
-------------- -------------- -------------- --------------
Adjusted E&S revenues (non-GAAP).................... $ 1,447,177 $ 1,161,856 $ 3,649,272 $ 2,749,661
Megawatt hours produced (in thousands).............. 25,882 23,375 63,213 53,809
All-in electricity price per megawatt hour generated $ 55.91 $ 49.71 $ 57.73 $ 51.10
- ------------
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
(2) From hedging, balancing and optimization activities related to our
generating assets.
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, 2003 and
2002, that represent purchased power and purchased gas sales and the costs we
incurred to purchase the power and gas that we resold during these periods (in
thousands, except percentage data):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- ------------------------------
2003 2002 2003 2002
--------------- --------------- --------------- --------------
Restated (1) Restated (1)
Total revenue....................................... $ 2,687,127 $ 2,474,698 $ 7,057,697 $ 5,563,777
Sales of purchased power for hedging and optimization 843,013 1,278,520 2,269,102 2,516,727
As a percentage of total revenue.................... 31.4% 51.7% 32.2% 45.2%
Sale of purchased gas for hedging and optimization.. 305,706 231,893 961,652 664,649
As a percentage of total revenue.................... 11.4% 9.4% 13.6% 11.9%
Total cost of revenue ("COR")....................... 2,330,973 2,124,146 6,342,211 4,785,630
Purchased power expense for hedging and optimization 835,892 1,059,841 2,254,560 2,039,955
As a percentage of total COR........................ 35.9% 49.9% 35.5% 42.6%
Purchased gas expense for hedging and optimization.. 293,241 218,443 941,312 671,196
As a percentage of total COR........................ 12.6% 10.3% 14.8% 14.0%
- ------------
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
The primary reasons for the size of these sales and costs of revenue items
include: (a) the significant level of Calpine Energy Services' ("CES's")
hedging, balancing and optimization activities; (b) volatile markets for
electricity and natural gas, which prompted us to frequently adjust our hedge
positions by buying and selling power and gas; (c) the accounting requirements
under Staff Accounting Bulletin ("SAB") No. 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 Asset," which require
us to show most of our hedging contracts on a gross basis (as opposed to netting
sales and cost of revenue); and (d) rules in effect associated with the NEPOOL
market in New England, which require that all power generated in NEPOOL be sold
directly to the Independent System Operator ("ISO") in that market; we then buy
from the ISO to serve our customer contracts. Generally accepted accounting
principles 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.
-40-
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2003 2002 2003 2002
-------------- -------------- -------------- ------------
Restated (1) Restated (1)
(In thousands)
Sales to NEPOOL from power we generated............. $ 88,413 $ 97,852 $ 258,945 $ 211,889
Sales to NEPOOL from hedging and other activity..... 29,375 33,964 117,345 78,770
------------- ------------- ------------- -------------
Total sales to NEPOOL............................ $ 117,788 $ 131,816 $ 376,290 $ 290,659
Total purchases from NEPOOL...................... $ 99,159 $ 113,659 $ 310,025 $ 274,838
- ------------
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
Results of Operations
Three Months Ended September 30, 2003, Compared to Three Months Ended
September 30, 2002 (in millions, unless otherwise stated, except for unit
pricing information, MW volumes and percentage data).
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Total revenue................................................ $ 2,687.1 $ 2,474.7 $ 212.4 8.6%
The increase in total revenue is explained by category below.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Electricity and steam revenue................................ $ 1,440.1 $ 943.2 $ 496.9 52.7%
Sales of purchased power for hedging and optimization........ 843.0 1,278.5 (435.5) (34.1)%
----------- ----------- ----------
Total electric generation and marketing revenue........... $ 2,283.1 $ 2,221.7 $ 61.4 2.8%
=========== =========== ==========
Electricity and steam revenue increased as we completed construction and
brought into operation seven new baseload power plants, eight new peaker
facilities and three expansion projects subsequent to September 30, 2002.
Average megawatts in operation of our consolidated plants increased by 34% to
21,821 MW while generation increased by 11%. The increase in generation lagged
behind the increase in average MW in operation as our baseload capacity factor
dropped to 60% in the three months ended September 30, 2003, from 72% in the
three months ended September 30, 2002, primarily due to the increased occurrence
of unattractive off-peak market spark spreads in certain areas. Average realized
electric price, before the effects of hedging, balancing and optimization,
increased from $40.35/MWh in 2002 to $55.64/MWh in 2003.
Sales of purchased power for hedging and optimization decreased in the
three months ended September 30, 2003, due primarily to lower volume in the
third quarter of 2003.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Oil and gas sales............................................ $ 27.9 $ 21.8 $ 6.1 28.0%
Sales of purchased gas for hedging and optimization.......... 305.7 231.9 73.8 31.8%
----------- ----------- ----------
Total oil and gas production and marketing revenue........ $ 333.6 $ 253.7 $ 79.9 31.5%
=========== =========== ==========
-41-
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption increased by $45.8 to $92.8 in 2003. Before
intercompany eliminations, oil and gas sales increased by $51.9 to $120.7 in
2003 from $68.8 in 2002 due primarily to 84% higher average realized natural gas
pricing in 2003.
Sales of purchased gas for hedging and optimization increased during 2003
due to a higher price environment.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Realized gain (loss) on power and gas transactions, net..... $ (0.1) $ 6.9 $ (7.0) (101.4)%
Unrealized gain (loss) on power
and gas transactions, net.................................. (10.9) (11.0) 0.1 (0.9)%
---------- ----------- ----------
Total mark-to-market activities, net...................... $ (11.0) $ (4.1) $ (6.9) 168.3%
========== =========== ==========
Total mark-to-market activities, which are shown on a net basis, results
from general market price movements against our open commodity derivative
positions, including positions accounted for as trading under EITF Issue No.
02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and
Risk Management Activities" ("EITF Issue No. 02-3") and other mark-to-market
activities. These commodity positions represent a small portion of our overall
commodity contract position. Realized revenue represents the portion of
contracts actually settled, while unrealized revenue represents changes in the
fair value of open contracts, and the ineffective portion of cash flow hedges.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Other revenue................................................ $ 81.5 $ 3.4 $ 78.1 2,297.1%
Other revenue increased during the three months ended September 30, 2003,
primarily due to a pre-tax gain of $69.4 in connection with our settlement with
Enron, primarily related to the final negotiated settlement of amounts owed
under terminated commodity contracts.
We also realized a $7.2 revenue contribution from Thomassen Turbine Systems
("TTS"), which we acquired in February 2003. This was partially offset by a
decline in third party revenue recorded by Power Systems Mfg. LLC ("PSM"), our
subsidiary that designs and manufactures certain spare parts for gas turbines,
as more of PSM's activity was related to intercompany orders with our power
generation segment.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Total cost of revenue........................................ $ 2,331.0 $ 2,124.1 $ 206.9 9.7%
The increase in total cost of revenue is explained by category below.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Plant operating expense...................................... $ 185.1 $ 141.2 $ 43.9 31.1%
Royalty expense.............................................. 7.0 4.7 2.3 48.9%
Purchased power expense for hedging and optimization......... 835.9 1,059.8 (223.9) (21.1)%
----------- ----------- ----------
Total electric generation and marketing expense........... $ 1,028.0 $ 1,205.7 $ (177.7) (14.7)%
=========== =========== ==========
-42-
Plant operating expense increased primarily due to seven new baseload power
plants, eight new peaker facilities and three expansion projects being completed
subsequent to September 30, 2002.
Royalty expense increased due to an increase in electric revenues at The
Geysers geothermal plants.
The decrease in purchased power expense for hedging and optimization was
due primarily to lower volume in the third quarter of 2003.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Oil and gas production expense............................... $ 23.0 $ 21.8 $ 1.2 5.5%
Oil and gas exploration expense.............................. 1.6 1.2 0.4 33.3%
----------- ----------- ----------
Oil and gas operating expense............................. 24.6 23.0 1.6 7.0%
Purchased gas expense for hedging and optimization........... 293.2 218.4 74.8 34.2%
----------- ----------- ----------
Total oil and gas operating and marketing expense...... $ 317.8 $ 241.4 $ 76.4 31.6%
=========== =========== ==========
Oil and gas production expense increased primarily due to higher production
taxes, and treating and transportation costs which were primarily the result of
higher oil and gas revenues plus an increase in operating cost and an increase
in the Canadian foreign exchange rate in 2003.
Oil and gas exploration expense increased primarily as a result of higher
seismic costs during the three months ended September 30, 2003.
Purchased gas expense for hedging and optimization increased in the three
months ended September 30, 2003, due to a higher price environment.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Fuel expense................................................. $ 800.3 $ 525.5 $ 274.8 52.3%
Fuel expense increased for the three months ended September 30, 2003, due
to a 11% increase in gas-fired megawatt hours generated and 40% higher gas
prices excluding the effects of hedging, balancing and optimization. This was
partially offset by increased value of internally produced gas, which is
eliminated in consolidation.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Depreciation, depletion and amortization expense............. $ 148.1 $ 121.7 $ 26.4 21.7%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to
September 30, 2002.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Other cost of revenue........................................ $ 8.4 $ 1.4 $ 7.0 500.0%
The increase is primarily due to $5.2 of Thomassen Turbine Systems ("TTS")
expense. TTS was acquired in February 2003.
-43-
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Income from unconsolidated investments in
power projects............................................. $ (4.1) $ (10.2) $ 6.1 (59.8)%
The decrease in income is primarily due to a decrease in the earnings
generated by the Acadia Energy Center as a result of the termination of the
tolling agreement with Aquila Merchant Services, Inc. ("AMS") and a $0.8
decrease in the earnings generated by the Aries Power Project as a result of
increased interest expense related to project level debt.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Equipment cancellation and impairment cost................... $ 0.6 $ 10.9 $ (10.3) (94.5)%
The pre-tax equipment cancellation and impairment charge in the three
months ended September 30, 2003, was primarily a result of $0.4 heat recovery
steam generator cancellation charges. The pre-tax equipment cancellation and
impairment charge in the three months ended September 30, 2002 was primarily a
result of $5.0 of impairment write downs associated with certain turbines. We
also had $3.7 in equipment cancellation charges and $2.1 in storage charges.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Project development expense.................................. $ 3.0 $ 7.6 $ (4.6) (60.5)%
Project development expense decreased as we placed certain existing
development projects on hold and scaled back new development activity.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
General and administrative expense........................... $ 61.8 $ 53.4 $ 8.4 15.7%
General and administrative expense increased due to $3.6 of stock-based
compensation expense associated with the Company's adoption of Financial
Accounting Standards Board ("FASB") Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation" ("SFAS No, 123")
effective January 1, 2003, on a prospective basis and due to higher outside
consulting expense, and higher cash-based employee compensation costs.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Interest expense............................................. $ 204.7 $ 127.8 $ 76.9 60.2%
Interest expense increased primarily due to the new plants entering
commercial operations (at which point capitalization of interest expense
ceases). Interest capitalized decreased from $123.2 for the three months ended
September 30, 2002, to $98.7 for the three months ended September 30, 2003. 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 and suspension of capitalization of
interest thereon. The remaining increase relates to an increase in average
indebtedness.
-44-
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Minority interest expense.................................... $ 2.6 $ 1.5 $ 1.1 73.3%
The increase is primarily due to an increase of $2.4 associated with the
Canadian Power Income Fund partially offset by a decrease of $1.0 associated
with Calpine Cogeneration Inc.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Other income................................................. $ (197.7) $ (35.5) $ (162.2) 456.9%
Other income in the three months ended September 30, 2003, is comprised
primarily of a $192.2 net pre-tax gain recorded in connection with the
redemption of various issuances of debt and preferred securities at a discount
and additionally includes an $8.1 foreign exchange translation gain. The income
in 2002 consisted primarily of a $38.6 gain on the termination of a power sales
agreement and $2.9 in foreign exchange transaction gains. These were partially
offset by $4.7 of letter of credit fees and a $3.0 loss on the sale of two
turbines.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Provision for income taxes................................... $ 41.9 $ 48.4 $ (6.5) (13.4)%
The effective rate declined to 15% in 2003 from 25% in 2002 as we trued-up
an 11% year-to-date effective rate. This effective rate variance is due to the
inclusion of significant permanent items in the calculation of the effective
rate, which are fixed in amount and have a significant effect on the effective
rates especially as such items become more material to net income.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Discontinued operations, net of tax.......................... $ (1.1) $ 9.3 $ (10.4) (111.8)%
During the three months ended September 30, 2003, we reclassified certain
revenue and expense related to our specialty data center engineering business
that we sold/discontinued in the second quarter of 2003. The 2002 activity
represents the results of our discontinued operations, which included the
specialty engineering business, the DePere Energy Center and Drakes Bay Field,
British Columbia and Medicine River oil and gas assets. With the exception of
the specialty engineering business, the sales of these assets were completed by
December 31, 2002, so their operations are not included in the 2003 activity.
Three Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Net income................................................... $ 237.8 $ 151.1 $ 86.7 57.4%
Our growing portfolio of operating power generation facilities contributed
to an 11% increase in electric generation production for the three months ended
September 30, 2003, compared to the same period in 2002. Electric generation and
marketing revenue increased 3% for the three months ended September 30, 2003, as
electricity and steam revenue increased by $496.9 or 53% as a result of the
higher production and higher electricity prices. This was partially offset by a
-45-
decline in sales of purchased power for hedging and optimization. Overall, we
achieved approximately $2,687.1 of revenue for the third quarter of 2003,
compared to approximately $2,474.7 for the third quarter of 2002. Operating
results for the three months ended September 30, 2003, reflect a decrease in
average spark spreads per megawatt-hour compared with the same period in 2002.
While we experienced an increase in realized electricity prices in 2003, this
was more than offset by higher fuel expense. At the same time, higher realized
oil and gas pricing resulted in an increase in oil and gas production margins
compared to the prior period. During the quarter, we recorded other revenue of
$69.4 in connection with its settlement with Enron, primarily related to the
termination of commodity contracts following the Enron bankruptcy.
Plant operating expense, interest expense and depreciation were higher due
to the additional plants in operation. Gross profit for the three months ended
September 30, 2003, increased approximately 2%, compared to the same period in
2002. For the three months ended September 30, 2003, overall financial results
significantly benefited from $192.2 of net pre-tax gains recorded in connection
with the repurchase of various issuances of debt and preferred securities at a
discount.
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
Nine Months Ended September 30, 2003, Compared to Nine Months Ended
September 30, 2002 (in millions, unless otherwise stated, except for unit
pricing information, MW volumes and percentage data).
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Total revenue................................................ $ 7,057.7 $ 5,563.8 $ 1,493.9 26.9%
The increase in total revenue is explained by category below.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Electricity and steam revenue................................ $ 3,634.7 $ 2,272.9 $ 1,361.8 59.9%
Sales of purchased power for hedging and optimization........ 2,269.1 2,516.7 (247.6) (9.8)%
----------- ----------- ----------
Total electric generation and marketing revenue........... $ 5,903.8 $ 4,789.6 $ 1,114.2 23.3%
=========== =========== ==========
Electricity and steam revenue increased as we completed construction and
brought into operation 7 new baseload power plants, 8 new peaker facilities and
3 expansion projects completed subsequent to September 30, 2002. Average
megawatts in operation of our consolidated plants increased by 48% to 19,874 MW
while generation increased by 17%. The increase in generation lagged behind the
increase in average MW in operation as our baseload capacity factor dropped to
55% in the nine months ended September 30, 2003 from 68% in the nine months
ended September 30, 2002, primarily due to the increased occurrence of
unattractive off-peak market spark spreads in certain areas, and to a lesser
extent due to unscheduled outages caused by equipment problems at certain of our
plants in the first half of 2003. Average realized electric price, before the
effects of hedging, balancing and optimization, increased from $42.24/MWh in
2002 to $57.50/MWh in 2003.
Sales of purchased power for hedging and optimization decreased in the nine
months ended September 30, 2003, due primarily to lower volume.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Oil and gas sales............................................ $ 83.4 $ 91.0 $ (7.6) (8.4)%
Sales of purchased gas for hedging and optimization.......... 961.6 664.7 296.9 44.7%
----------- ----------- ----------
Total oil and gas production and marketing revenue........ $ 1,045.0 $ 755.7 $ 289.3 38.3%
=========== =========== ==========
-46-
Oil and gas sales are net of internal consumption, which is eliminated in
consolidation. Internal consumption increased by $203.6 to $320.5 in 2003.
Before intercompany eliminations, oil and gas sales increased by $196.0 to
$403.9 in 2003 from $207.9 in 2002 due primarily to 99.6% higher average
realized natural gas pricing in 2003.
Sales of purchased gas for hedging and optimization increased during 2003
due to a higher price environment.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Realized gain (loss) on power and gas transactions, net...... $ 30.2 $ 15.3 $ 14.9 97.4%
Unrealized gain (loss) on power and gas transactions, net.... (18.9) (6.2) (12.7) 204.8%
----------- ----------- ----------
Total mark-to-market activities, net...................... $ 11.3 $ 9.1 $ 2.2 24.2%
=========== =========== ==========
Total mark-to-market activities, which are shown on a net basis, result
from general market price movements against our open commodity derivative
positions not designated as hedges, including positions accounted for as trading
under EITF Issue No. 02-3 and other mark-to-market activities. These commodity
positions represent a small portion of our overall commodity contract positions.
It increased due to favorable power and gas price movements. Realized revenue
represents the portion of contracts actually settled, while unrealized revenue
represents changes in the fair value of open contracts, and the ineffective
portion of cash flow hedges.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Other revenue................................................ $ 97.6 $ 9.4 $ 88.2 938.3%
Other revenue increased during the nine months ended September 30, 2003,
primarily due to a $69.4 pre-tax gain in connection with our settlement with
Enron, primarily related to the final negotiated settlement of amounts owed
under the terminated commodity contracts.
We also realized $16.3 of revenue from Thomassen Turbine Systems, ("TTS"),
which we acquired in February 2003. Additionally our recently formed Calpine
Power Services unit contributed revenues of $4.9 in 2003.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Total cost of revenue........................................ $ 6,342.2 $ 4,785.6 $ 1,556.6 32.5%
The increase in total cost of revenue is explained by category below.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Plant operating expense...................................... $ 514.5 $ 376.0 $ 138.5 36.8%
Royalty expense.............................................. 18.8 13.1 5.7 43.5%
Purchased power expense for hedging and optimization......... 2,254.6 2,040.0 214.6 10.5%
----------- ----------- ----------
Total electric generation and marketing expense........... $ 2,787.9 $ 2,429.1 $ 358.8 14.8%
=========== =========== ==========
Plant operating expense increased due to seven new baseload power plants,
eight new peaker facilities and three expansion projects being completed
subsequent to September 30, 2002. In addition, during the nine months ended
September 30, 2003, we recorded reserves of $6.6 for generator and turbine
combustor equipment repairs after reaching agreement with a vendor, which
accepted responsibility for most of the total costs incurred.
-47-
Royalty expense increased due to an increase in electric revenues at The
Geysers geothermal plants.
The increase in purchased power expense for hedging and optimization was
due primarily to higher electricity prices in 2003.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Oil and gas production expense............................... $ 68.8 $ 61.4 $ 7.4 12.1%
Oil and gas exploration expense.............................. 10.5 6.0 4.5 75.0%
----------- ----------- ----------
Oil and gas operating expense............................. 79.3 67.4 11.9 17.7%
Purchased gas expense for hedging and optimization........... 941.3 671.2 270.1 40.2%
----------- ----------- ----------
Total oil and gas operating and marketing expense...... $ 1,020.6 $ 738.6 $ 282.0 38.2%
=========== =========== ==========
Oil and gas production expense increased primarily due to higher production
taxes, and treating and transportation costs which were primarily the result of
higher oil and gas revenues plus an increase in operating cost and an increase
in the Canadian foreign exchange rate in 2003.
Oil and gas exploration expense increased primarily as a result of
expensing $4.5 of dry hole drilling costs during the nine months ended September
30, 2003.
Purchased gas expense for hedging and optimization increased in the nine
months ended September 30, 2003, due to a higher price environment.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Fuel expense................................................. $ 2,005.9 $ 1,208.3 $ 797.6 66.0%
Fuel expense increased for the nine months ended September 30, 2003 due to
a 17.5% increase in gas-fired megawatt hours generated and 48.2% higher gas
prices excluding the effects of hedging, balancing and optimization, which was
partially offset by increased usage of internally produced gas, which is
eliminated in consolidation.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Depreciation, depletion and amortization expense............. $ 423.0 $ 320.3 $ 102.7 32.1%
Depreciation, depletion and amortization expense increased primarily due to
the additional power facilities in consolidated operations subsequent to
September 30, 2002.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Other cost of revenue........................................ $ 20.5 $ 4.5 $ 16.0 355.6%
The increase is primarily due to $11.3 of TTS expense. TTS was acquired in
February 2003.
-48-
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Income from unconsolidated investments in
power projects............................................. $ (68.6) $ (10.6) $ (58.0) 547.2%
The increase is primarily due to a $52.8 gain recognized on the termination
of the tolling arrangement with AMS on the Acadia Energy Center (see Note 6 of
the Notes to Consolidated Condensed Financial Statements) and due to $18.2 in
operating earnings generated by this facility. This facility went operational in
August of 2002.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Equipment cancellation and impairment charge................. $ 19.9 $ 193.6 $ (173.7) (89.7)%
In the nine months ended September 30, 2003, the pre-tax equipment
cancellation and impairment charge was primarily a result of a loss of $17.2 in
connection with the sale of two turbines and also commitment cancellation costs
and storage and suspension costs for unassigned equipment. The pre-tax equipment
cancellation and impairment charge in the nine months ended September 30, 2002,
was primarily a result of the 35 steam and gas turbine order cancellations and
the cancellation of certain other equipment based primarily on forfeited
prepayments made in prior periods.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Project development expense.................................. $ 14.1 $ 29.5 $ (15.4) (52.2)%
Project development expense decreased as we placed certain existing
development projects on hold and scaled back new development activity.
Additionally, impairment write-offs of capitalized project costs decreased to
$3.4 in the nine months ended September 30, 2003, from $6.2 in the prior year.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
General and administrative expense........................... $ 179.3 $ 163.6 $ 15.7 9.6%
The increase is due primarily to $12 of stock-based compensation expense
associated with the Company's adoption of SFAS No. 123 prospectively effective
January 1, 2003.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Interest expense............................................. $ 496.5 $ 280.6 $ 215.9 76.9%
Interest expense increased primarily due to the new plants entering
commercial operations (at which point capitalization of interest expense
ceases). Interest capitalized decreased from $457.3 for the nine months ended
September 30, 2002, to $333.7 for the nine months ended September 30, 2003. 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
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of certain of our development projects and suspension of capitalization of
interest thereon. The remaining increase relates to an increase in average
indebtedness and an increase in the amortization of terminated interest rate
swaps.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Interest income.............................................. $ (27.8)$ (32.8) $ 5.0 (15.2)%
The decrease is primarily due to lower cash balances and lower interest
rates in 2003.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ------------ ----------- ----------
Restated (1)
Minority interest expense.................................... $ 10.2 $ 1.9 $ 8.3 436.8%
The increase is primarily due to an increase of $9.0 associated with the
Canadian Power Income Fund.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Other income................................................. $ (149.4)$ (51.8) $ (97.6) 188.4%
Other income in the nine months ended September 30, 2003, is comprised
primarily of $199.0 net pre-tax gain recorded in connection with the repurchase
of various issuances of debt and preferred securities at a discount. This income
was offset primarily by $36.2 of foreign exchange translation losses, and $10.5
of letter of credit fees. The foreign exchange translation losses recognized
into income were mainly due to a strong Canadian dollar in the nine-month
period. In 2002 we recorded a $38.6 gain on the termination of a power sales
agreement, a $9.7 gain from the sale of our interest in the Lockport facility,
$7.0 of partial recovery from Automated Credit Exchange for losses incurred on
reclaim trading credit transactions, and a gain of $3.5 from the repurchase of
our Zero-Coupon Convertible Debentures Due 2021 at a discount. These gains were
partially offset by letter of credit fees of $11.0, foreign exchange translation
losses of $1.0, and $3.6 for cost of a forfeited deposit on an asset purchase
that did not close in 2002.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Provision for income taxes................................... $ 21.5 $ 33.6 $ (12.1) (36.0)%
For the nine months ended September 30, 2003, the effective rate declined
to 11% from 21 % for the nine months ended 2002. This effective rate variance is
due to the inclusion of significant permanent items in the calculation of the
effective rate, which are fixed in amount and have a significant effect on the
effective rates especially as such items become more material to net income.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Discontinued operations, net of tax.......................... $ (11.3)$ 20.2 $ (31.5) (155.9)%
-50-
During the nine months ended September 30, 2003, we sold our specialty data
center engineering business, reflecting the soft market for data centers for the
foreseeable future. The 2002 discontinued operations activity included the
specialty engineering business, the DePere Energy Center as well as the Drakes
Bay Field, British Columbia and Medicine River oil and gas assets. With the
exception of the specialty engineering business, the sales of these assets were
completed by December 31, 2002; therefore, their results are not included in the
2003 activity.
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Cumulative effect of a change in accounting principle,
net of tax................................................. $ 0.5 $ -- $ 0.5 100.0%
The cumulative effect of a change in accounting principle represents a
gain, net of tax effect from adopting SFAS No. 143, "Accounting for Asset
Retirement Obligations."
Nine Months Ended
September 30,
2003 2002 $ Change % Change
----------- ----------- ---------- ----------
Restated (1)
Net income................................................... $ 162.4 $ 143.8 $ 18.6 12.9%
Our growing portfolio of operating power generation facilities contributed
to a 17% increase in electric generation production for the nine months ended
September 30, 2003, compared to the same period in 2002. Electric generation and
marketing revenue increased 23% for the nine months ended September 30, 2003, as
electricity and steam revenue increased by $1,361.8 or 60%, as a result of the
higher production and higher electricity prices. This was partially offset by a
decline in sales of purchased power for hedging and optimization. Operating
results for the nine months ended September 30, 2003, reflect a decrease in
average spark spreads per megawatt-hour compared with the same period in 2002.
While we experienced an increase in realized electricity prices in 2003, this
was more than offset by higher fuel expense. At the same time, higher realized
oil and gas pricing resulted in an increase in oil and gas production margins
compared to the prior period. During the nine months of 2003, we recorded other
revenue of $69.4 in connection with its settlement with Enron, primarily related
to the termination of commodity contracts following the Enron bankruptcy.
Plant operating expense, interest expense and depreciation were higher due
to the additional plants in operation. Gross profit for the nine months ended
September 30, 2003, decreased approximately 8%, compared to the same period in
2002. For the nine months ended September 30, 2003, overall financial results
significantly benefited from $199.0 of net pre-tax gains recorded in connection
with the repurchase of various issuances of debt and preferred securities at a
discount.
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
Liquidity and Capital Resources
General - Beginning in the latter half of 2001, and continuing through 2002
and into 2003, there has been a significant contraction in the availability of
capital for participants in the energy sector, although a more favorable climate
for refinancings has been observed in 2003. This contraction has been due to a
range of factors, including uncertainty arising from the collapse of Enron Corp.
and a surplus of electric generating capacity in certain markets. Contracting
credit markets and decreased spark spreads have adversely impacted our liquidity
and earnings. While we have been able to access the capital and bank credit
markets, it has been on significantly different terms than in the past. We
recognize that terms of financing available to us in the future may not be
attractive. To protect against this possibility and due to current market
conditions, we scaled back our capital expenditure program for 2002 and 2003 to
enable us to conserve our available capital resources. We have refinanced all of
our debt facilities of significance coming due in 2003 and the first half of
2004. The obligations coming due in the second half of 2004 and our plan for
refinancing or extending them are discussed below.
To date, we have obtained cash from our operations; borrowings under our
term loan and revolving credit facilities; issuance of debt, equity, trust
preferred securities and convertible debentures; proceeds from sale/ leaseback
transactions, sale or partial sale of certain assets, contract monetizations and
-51-
project financing. We have utilized this cash to fund our operations, service or
prepay debt obligations, fund acquisitions, develop and construct power
generation facilities, finance capital expenditures, support our hedging,
balancing, optimization and trading activities at CES, and meet our other cash
and liquidity needs. Our business is capital intensive. Our ability to
capitalize on growth opportunities is dependent on the availability of capital
on attractive terms. The availability of such capital in today's environment is
uncertain. Our strategy is also to reinvest our cash from operations into our
business development and construction program or to use it to reduce debt,
rather than to pay cash dividends. As discussed below, we have a
liquidity-enhancing program underway to fund the completion of our current
construction portfolio, for refinancing and for general corporate purposes.
In May and June 2003 our $950 million in secured working capital revolving
credit facilities matured and were extended, ultimately to July 16, 2003. On
July 16, 2003, the Company closed a $3.3 billion term loan and second-priority
senior secured notes offering ("notes offering") and repaid the outstanding
balance on the revolving credit facilities. We also repaid the $949.6 million in
funded borrowings outstanding under our $1.0 billion secured term credit
facility which was to mature in May 2004. We have also retired nearly $1.4
billion under various debt and preferred securities issuances in 2003 primarily
with proceeds of the notes offering but also through debt and preferred
securities for equity swaps.
In November 2003 our $1.0 billion secured revolving construction financing
facility through Calpine Construction Finance Company, L.P. was scheduled to
mature. On August 14, 2003, the Company's wholly owned subsidiaries, Calpine
Construction Finance Company, L.P. ("CCFC I") and CCFC Finance Corp., closed
$750 million institutional term loan and secured notes offering. On September
25, 2003, CCFC I and CCFC Finance Corp. closed on a $50 million secured notes
offering. This financing represented an add-on to the $750 million CCFC I
offering completed on August 14, 2003. Net proceeds from these offerings were
used to refinance the majority of the $930.1 million outstanding at June 30,
2003, under the CCFC I project financing. The remainder of the facility was
repaid from cash proceeds from the notes offering.
In November 2004 our $2.5 billion secured revolving construction financing
facility through Calpine Construction Finance Company II, LLC ("CCFC II") will
mature, requiring us to refinance this indebtedness. As of September 30, 2003,
there was $2,167.9 million outstanding under this facility. We intend to
refinance or extend this facility sometime in 2004, prior to its expiration.
Since this facility bears a very low interest rate, it is not economical to
refinance it too far in advance of its expiration. Our ability to refinance this
indebtedness will depend, in part, on events beyond our control, including the
significant contraction in the availability of capital for participants in the
energy sector, and actions taken by rating agencies.
The holders of our 4% Convertible Senior Notes Due 2006 ("convertibles")
have a right to require us to repurchase them at 100% of their principal amount
plus any accrued and unpaid interest on December 26, 2004. We can effect such a
repurchase with cash, shares of Calpine stock or a combination of the two. In
2003 we have retired in the open market approximately $177.0 million of the
outstanding principal amount primarily with the proceeds of the notes offering
discussed above.
On November 6, 2003, we priced our separate offerings of senior unsecured
convertible notes and second priority senior secured notes. The offering
includes $400 million of 9.875% Second Priority Senior Secured Notes due 2011,
offered at 98.01% of par. This offering is expected to close on November 18,
2003. We expect to use the net proceeds from this offering to purchase
outstanding senior notes. The other offering includes $600 million of 4.75%
Senior Unsecured Convertible Notes due 2023. The securities will be convertible
into cash and into shares of Calpine common stock at a price of $6.50 per share,
which represents a 38% premium on the November 6, 2003 New York Stock Exchange
closing price of $4.71 per Calpine common share. In addition, we have granted
the initial purchaser an option to purchase an additional $300 million of the
senior unsecured convertible notes. This offering is expected to close on
November 14, 2003. Net proceeds from this offering will be used to repurchase
existing indebtedness.
In addition, $238.5 million of our outstanding Remarketable Term Income
Deferrable Equity Securities ("HIGH TIDES") are scheduled to be remarketed no
later than November 1, 2004, $360.0 million of our HIGH TIDES are scheduled to
be remarketed no later than February 1, 2005 and $517.5 million of our HIGH
TIDES are scheduled to be remarketed no later than August 1, 2005. In the event
of a failed remarketing, the relevant HIGH TIDES will remain outstanding as
convertible securities at a term rate equal to the treasury rate plus 6% per
annum and with a term conversion price equal to 105% of the average closing
price of our common stock for the five consecutive trading days after the
applicable final failed remarketing termination date. While a failed remarketing
of our HIGH TIDES would not have an effect on our liquidity position, it would
impact our calculation of diluted earnings per share.
-52-
We expect to have sufficient liquidity from cash flow from operations,
borrowings available under lines of credit, access to sale/leaseback and project
financing markets, sale of certain assets and cash balances to satisfy all
obligations under our other outstanding indebtedness, and to fund anticipated
capital expenditures and working capital requirements for the next twelve
months.
Cash Flow Activities - The following table summarizes our cash flow
activities for the periods indicated:
Nine Months Ended
September 30,
2003 2002
--------------- --------------
Restated (1)
(In thousands)
Beginning cash and cash equivalents......................................... $ 579,486 $ 1,594,144
Net cash provided by (used in):
Operating activities..................................................... 171,332 799,370
Investing activities..................................................... (1,836,581) (3,242,777)
Financing activities..................................................... 2,046,489 1,573,698
Effect of exchange rates changes on cash and cash equivalents............ 8,946 2,277
-------------- --------------
Net increase (decrease) in cash and cash equivalents..................... 390,186 (867,432)
-------------- --------------
Ending cash and cash equivalents............................................ $ 969,672 $ 726,712
============== ==============
- ------------
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
Operating activities for the nine months ended September 30, 2003, provided
net cash of $171.3 million, compared to $799.4 million for the same period in
2002. The decrease in operating cash flow between periods is primarily due to
the working capital funding requirements. During the nine months ended September
30, 2003, working capital used approximately $635.5 million, as compared to
$81.1 million in the same period last year. The growth in short term assets such
as margin deposits and accounts receivable accounted for the majority of this
difference, which is the result of hedging activities, the overall growth in our
revenues, and the timing of receivables collections. For example, the collection
from escrow of approximately $222.3 million in 2002 for the PG&E past due
pre-petition receivables that were sold to a third party in December 2001
augmented operating cash flow in 2002 when compared to 2003. Excluding the
effects of working capital reflected as "Changes in operating assets and
liabilities, net of effects of acquisitions," our operating cash flow decreased
by approximately $73.6 million. Although average spark spreads were lower in
2003 than in 2002, increased electrical generation resulted in higher revenues,
and subsequently, higher receivables balances. Similarly, natural gas price
increases benefited our oil and gas operating results on similar production.
Additionally, in 2003, we received $105.5 million from the Acadia joint venture,
following the termination of the power purchase agreement with Aquila and the
restructuring of our interest in the joint venture. See Note 6 of the Notes to
Consolidated Condensed Financial Statements for further discussion.
Investing activities for the nine months ended September 30, 2003, consumed
net cash of $1,836.6 million, as compared to $3,242.8 million in the same period
of 2002. In both periods, capital expenditures represent the majority of
investing cash outflows. The decrease between periods is due to the completion
of construction on several facilities during 2002 and 2003, and due to our
revised capital expenditure program, which has reduced capital investments in
2003.
Financing activities for the nine months ended September 30, 2003, provided
$2,046.5 million, compared to $1,573.7 million in the prior year. Current year
cash inflows are primarily the result of several financing transactions,
including $3.5 billion from the issuance of senior notes during the third
quarter, $802.2 million from the Power Contract Financing, L.L.C. ("PCF")
financing transaction, $785.5 million from the refinancing of our CCFC I credit
facility, $301.7 million from the issuance of secured notes by our wholly owned
subsidiary Gilroy Energy Center ("GEC") LLC, $126.5 million from secondary trust
unit offerings from our Canadian Income Trust, $82.8 million from the
monetization of one of our power sales agreements, $82.0 million, $88.0 million,
and $74.0 million from the sales of preferred interests in the cash flows of our
King City, Auburndale, and GEC Holdings, LLC facilities and additional
borrowings under our revolvers. This was partially offset by financing costs and
$4.2 billion in debt repayments and repurchases. We expect that the significant
financing transactions will allow us to continue to retire short term debt and
will also enable us to make further repurchases of other long term securities.
In the same period of 2002, financing inflows were comprised of $754.9 million
from the issuance of common stock, and $2,062.3 million in debt financing,
-53-
partially offset by the use of $869.7 million used to repay our Zero Coupon
Convertible Debentures Due 2021, in addition to other repayments of project
financing.
Counterparties and Customers - As of September 30, 2003, we had collection
exposures after established reserves from certain of our counterparties as
follows: approximately $10.1 million with NRG Power Marketing, Inc.;
approximately $13.1 million with Aquila, Inc. and its affiliate, Aquila Merchant
Services, Inc. and approximately $4.4 million with Mirant Americas Energy
Marketing, L.P. While we cannot predict the likelihood of default by our
customers, we are continuing to closely monitor our positions and will adjust
the values of the reserves as conditions dictate. See Note 10 of the Notes to
Consolidated Condensed Financial Statements for more information.
Enron Corporation, Inc., and a number of its subsidiaries and affiliates
(including Enron North America Corp. ("ENA") and Enron Power Marketing, Inc.
("EPMI")) (collectively "Enron Bankrupt Entities") filed for Chapter 11
bankruptcy protection on December 2, 2001. At the time of the filing, CES was a
party to various open energy derivatives, swaps, and forward power and gas
transactions stemming from agreements with ENA and EPMI. On November 14, 2001,
CES, ENA, and EPMI entered into a Master Netting Agreement, which granted the
parties a contractual right to setoff amounts owed between them pursuant to the
above agreements. The above agreements were terminated by CES on December 10,
2001. The Master Netting Agreement however remained in place. In October 2002
Calpine and various affiliates filed proofs of claim against the Enron Bankrupt
Entities.
Calpine and Enron reached a final settlement agreement with regard to the
Company's terminated trading positions with Enron. The agreement was approved by
the Unsecured Creditors' committee on July 24, 2003, and by the Bankruptcy Court
on August 7, 2003. The settlement is now final. Under the terms of the
settlement agreement, CES will make five monthly installment payments of $19.4
million beginning August 22, 2003, and ending December 22, 2003. The nominal
total of the payments to Enron will be $97.0 million ($95.7 million on a
discounted basis). Once final payment is made, all claims between the parties
relating to these matters will be released and extinguished.
In connection with this settlement, we recorded a pretax gain of $69.4
million related to settlement of net liabilities associated with terminated
derivative positions and receivables and payables with Enron Corporation, and a
number of its subsidiaries and affiliates. Prior to reaching final settlement,
we had recorded a net liability to Enron relating to these transactions. The
ultimate obligation to Enron based upon the terms of the final negotiated
settlement agreement was less than the net liability we had previously recorded.
We recorded the difference as other revenue. The reduction to the previously
recorded net liability was the result of giving economic recognition in the
settlement to value associated with: 1) commodity contracts that were not given
accounting recognition (i.e. in-the-money commodity contracts accounted for as
normal purchases and sales), 2) forgiveness of liabilities due to differences in
discounting assumptions, and 3) claims recoveries.
A significant portion of the liability to Enron related to commodity
derivatives that had been designated as hedges of price risk associated with our
natural gas consumption, and to a lesser degree, our electric power generation.
Under the hedge accounting rules, losses associated with designated hedges are
recorded in a company's balance sheet and recognized into earnings when the
transactions being hedged occur even if the hedge instruments are terminated
prior to the occurrence of the hedged transactions. As of September 30, 2003, we
had reclassified losses of approximately $150.8 million into income related to
2003 transactions hedged by Enron derivatives. Most of these losses were
recorded as fuel expense consistent with our policy for classifying gains and
losses on designated fuel hedges. Because of the character of the transactions
giving rise to the Enron liability, we classified the gain on the settlement as
other revenue.
We have a note receivable from Pacific Gas and Electric Company ("PG&E")
and are receiving our monthly note repayments of approximately $1.7 million as
scheduled per the contract, as well as current payments on our trade
receivables. See Note 10 of the Notes to Consolidated Financial Statements in
our 2002 Form 10-K, updated by the Company's Form 8-K, filed on October 23,
2003, for more information on our contract activity with PG&E. On October 30,
2003, we entered into an agreement to sell this note receivable at a discount of
approximately $25 million, subject to obtaining certain third-party consents
within a specified time period. The proceeds are expected to be used primarily
to repurchase certain of our outstanding debt securities at a discount. The
final terms of the sale, including the purchase price, will be disclosed
following the actual closing of the sale.
Letter of Credit Facilities - At September 30, 2003 and December 31, 2002,
we had approximately $453.7 million and $685.6 million, respectively, in letters
of credit outstanding under various credit facilities to support CES risk
management, and other operational and construction activities. Of the total
letters of credit outstanding, $326.0 million and $573.9 million, respectively,
-54-
were issued under the working capital facility and the cash collateral facility
at September 30, 2003 and under the working capital facility at December 31,
2002.
CES Margin Deposits and Other Credit Support - As of September 30, 2003 and
December 31, 2002, CES had deposited net amounts of $179.0 million and $25.2
million, respectively, in cash as margin deposits with third parties and had
letters of credit outstanding of $20.3 million and $106.1 million, respectively.
CES uses these margin deposits and letters of credit as credit support for the
gas procurement as well as risk management activities it conducts on the
Company's behalf. The amount of credit support required to support CES's
operations is a function primarily of the changes in fair value of commodity
contracts that CES has entered into and our credit rating.
Contractual Obligations - Our contractual obligations as of September 30,
2003, are as follows (in thousands):
October
Through
December
Contractual Obligations 2003 2004 2005 2006 2007 Thereafter Total
------------------------------ ----------- ----------- ---------- ----------- ---------- ------------ -----------
Notes payable and borrowings
under lines of credit
and term loan (1)................ $ 36,046 $ 255,539 $ 193,274 $ 197,214 $ 150,813 $ 437,266 $ 1,270,152
Capital lease obligation (1)....... 502 3,733 4,406 5,468 5,980 177,857 197,946
Construction/project financing (1). 10,835 2,233,411 61,888 66,064 205,815 1,590,390 4,168,403
Convertible Senior Notes Due
2006 (2)......................... -- -- -- 1,047,996 -- -- 1,047,996
Other Senior Notes (2)............. -- -- 224,630 381,165 373,628 4,783,638 5,763,061
Second Priority Senior Secured 3,125 12,500 12,500 12,500 1,209,375 2,050,000 3,300,000
Notes (2)........................
First Priority Senior Secured
Notes (2)........................ 500 2,000 2,000 2,000 193,500 -- 200,000
---------- ---------- --------- ---------- ---------- ----------- -----------
Total Senior Notes.............. 3,625 14,500 239,130 395,665 1,776,503 6,833,638 9,263,061
Total operating lease.............. 38,140 96,688 83,169 81,772 82,487 1,393,364 1,775,620
Turbine commitments................ 56,963 143,935 17,737 2,516 -- -- 221,151
HIGH TIDES......................... -- -- -- -- -- 1,116,000 1,116,000
---------- ---------- --------- ---------- ---------- ----------- -----------
Total........................ $ 146,111 $2,747,806 $ 599,604 $1,796,695 $2,221,598 $11,548,515 $19,060,329
========== ========== ========= ========== ========== =========== ===========
- ------------
(1) Structured as an obligation(s) of certain subsidiaries of Calpine
Corporation without recourse to Calpine Corporation. However, default on
these instruments could potentially trigger cross-default provisions in the
Company's recourse financings.
(2) An obligation of or with recourse to Calpine Corporation.
We repurchased debt securities during the three months ended September 30,
2003, of approximately $1.2 billion in aggregate outstanding principal amount at
a cost of $992.1 million plus accrued interest to the settlement dates. We
recorded a pre-tax gain on these transactions in the amount of $185.1 million,
net of write-offs of unamortized deferred financing costs and the associated
unamortized premiums or discounts.
Debt and preferred securities totaling $157.5 million in aggregate
outstanding principal amount were exchanged for 25.2 million shares of Calpine
common stock in privately negotiated transactions during the three months ended
September 30, 2003. We recorded a pre-tax gain on these transactions in the
amount of $22.6 million, net of write-offs of unamortized deferred financing
costs and the associated unamortized premiums or discounts associated with the
issuance of these Senior Notes and preferred securities.
We repurchased Senior Notes subsequent to September 30, 2003, totaling
approximately $11.7 million in aggregate outstanding principal amount at a cost
of approximately $8.3 million plus accrued interest to the settlement dates. We
expect to record a pre-tax gain on these transactions in the amount of $3.2
million, net of write-offs of the associated unamortized deferred financing
costs and unamortized premiums or discounts.
Convertible Senior Notes due 2006 totaling $25.0 million in aggregate
outstanding principal amount were exchanged for 4.8 million shares of Calpine
common stock in privately negotiated transactions subsequent to September 30,
2003. We expect to record a pre-tax gain on these transactions in the amount of
$0.2 million, net of write-offs of the associated unamortized deferred financing
costs and unamortized premiums or discounts.
-55-
Our senior notes indentures and our credit facilities contain financial and
other restrictive covenants. Any failure to comply could give holders of debt
under the relevant instrument the right to accelerate the maturity of all debt
outstanding thereunder if the default was not cured or waived. In addition,
holders of debt under other instruments typically would have cross-acceleration
provisions, which would permit them also to elect to accelerate the maturity of
their debt if another debt instrument was accelerated upon the occurrence of
such an uncured event of default.
In July 2003 we completed a restructuring of our agreements with Siemens
Westinghouse Power Corporation for 20 gas and 2 steam turbines. The new
agreement provides for later payment dates, which are in line with our
construction program. The table above sets forth future turbine payments for
construction and development projects, as well as for unassigned turbines. It
includes previously delivered turbines, payments and delivery year for the
remaining 10 turbines to be delivered as well as payment required for the
potential cancellation costs of the remaining 74 gas and steam turbines. The
table above does not include payments that would result if we were to release
for manufacturing any of these remaining 74 turbines.
One of our wholly owned subsidiaries, South Point Energy Center, LLC,
leases the 530-MW South Point power facility located in Arizona, pursuant to
certain facility lease agreements. We became aware that a technical default had
occurred under such facility lease agreements as a result of an inadvertent
pledge of the ownership interests in such subsidiary granted pursuant to certain
separate loan facilities entered into by us. The South Point facility lease was
entered into as part of a larger transaction, which also involved the lease by
two of our other subsidiaries of the following two power facilities: the 850-MW
Broad River power facility located in South Carolina, and the 520-MW RockGen
power facility located in Wisconsin. As all three lease transactions were part
of the same overall transaction, the facility lease agreements for Broad River
and RockGen contain cross-default provisions to the South Point facility lease
agreements and, therefore, a technical default also existed under the Broad
River and RockGen facility lease agreements. However, upon the release of the
inadvertent South Point pledge, which occurred in September 2003, the defaults
under the Broad River, RockGen and South Point facility lease agreements were
cured.
We own a 32.3% interest in the unconsolidated equity method investee
Androscoggin Energy LLC ("AELLC"). AELLC owns the 160-MW Androscoggin Energy
Center located in Maine and has construction debt of $62.6 million outstanding
as of September 30, 2003. The debt is non-recourse to Calpine Corporation (the
"AELLC Non-Recourse Financing"). On September 30, 2003, our investment balance
was $9.8 million and our notes receivable balance due from AELLC was $12.0
million. On August 8, 2003, AELLC received a letter from the lenders claiming
that certain events of default have occurred under the credit agreement for the
AELLC Non-Recourse Financing, including, among other things, that the project
has been and remains in default under its debt agreement because the lending
syndication has declined to extend the dates for the conversion of the
construction loan by a certain date. AELLC is currently discussing with the
banks a forbearance arrangement until an agreement is reached concerning the
extension, conversion or repayment of the debt; however, the outcome is
uncertain at this point. Also, the steam host for the AELLC project,
International Paper Company ("IP"), filed a complaint against AELLC in October
2000, which is disclosed in Note 12 "Commitments and Contingencies" in the Notes
to Consolidated Condensed Financial Statements. IP's complaint has been a
complicating factor in converting the construction debt to long term financing.
We also own a 50% interest in the unconsolidated equity method investee
Merchant Energy Partners Pleasant Hill, LLC ("Aries"). Aries owns the 591-MW
Aries Power Project located in Pleasant Hill, Missouri, and has construction
debt of $190.0 million as of September 30, 2003, that was due on June 26, 2003.
Due to the default, the partners were required to contribute their proportionate
share of $75 million in additional equity. During the second quarter, we drew
down $37.5 million under our working capital revolver to fund our equity
contribution. The management of Aries is in negotiation with the lenders to
extend the debt while it continues to negotiate a term loan for the project. The
project is technically in default of its debt agreement until the extension is
signed. We believe that the project will be able to obtain long-term project
financing at commercially reasonable terms. As a result of this event, we have
reviewed our $59.0 million investment in the Aries project and believe that the
investment is not impaired.
We are a party to a Letter of Credit and Reimbursement Agreement dated as
of December 19, 2000, with Credit Suisse First Boston ("CSFB"), pursuant to
which CSFB issued a letter of credit with a maximum face amount of $78.3 million
for our account, approximately 50% of which is secured by a letter of credit
issued by another bank. CSFB has advised us that CSFB believes that we may have
failed to comply with certain covenants under the Letter of Credit and
Reimbursement Agreement relating to our ability to incur indebtedness and grant
liens, and has requested that we provide security for the remaining unsecured
balance outstanding under the CSFB letter of credit. We believe we have complied
with such covenants and we are in active discussions with CSFB concerning this
matter. We do not believe this matter will have a material adverse effect on us.
-56-
Capital Spending - Development and Construction
Construction and development costs consisted of the following at September
30, 2003 (dollars in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment
-------- ------------ ------------ ----------- -----------
Projects in active construction............... 14 $ 4,239,507 $ 1,540,257 $ -- $ --
Projects in advanced development.............. 10 666,727 570,967 111,761 --
Projects in suspended development............. 6 603,505 331,823 13,973 --
Projects in early development................. 3 3,673 -- 8,625 --
Other capital projects........................ NA 104,256 -- -- --
Unassigned equipment.......................... NA -- -- -- 117,795
------------ ------------ ----------- -----------
Total construction and development costs... $ 5,617,668 $ 2,443,047 $ 134,359 $ 117,795
============ ============ =========== ===========
Projects in Active Construction - The 14 projects in active construction
are estimated to come on line from December 2003 to June 2006. These projects
will bring on line approximately 6,720 and 7,863 MW of base load and base load
with peaking capacity, respectively. Interest and other costs related to the
construction activities necessary to bring these projects to their intended use
are being capitalized. The estimated cost to complete these projects, net of
expected project financing proceeds, is approximately $0.8 billion. We plan to
spend $0.1 billion, $0.3 billion, $0.3 billion and $0.1 billion in 2003, 2004,
2005 and 2006, respectively.
Projects in Advanced Development - There are 10 projects in advanced
development. These projects will bring on line approximately 5,439 and 6,505 MW
of base load and base load with peaking capacity, respectively. Interest and
other costs related to the development activities necessary to bring these
projects to their intended use are being capitalized. However, the
capitalization of interest has been suspended on two projects for which
development activities are substantially complete but construction will not
commence until a power purchase agreement and financing are obtained. The
estimated cost to complete the ten projects in advanced development is
approximately $3.2 billion. Our current plan is to project finance these costs
as power purchase agreements are arranged.
Suspended Development Projects - Due to current electric market conditions,
we have ceased capitalization of additional development costs and interest
expense on certain development projects on which work has been suspended.
Capitalization of costs may recommence as work on these projects resumes, if
certain milestones and criteria are met indicating that it is again highly
probable that the costs will be recovered through future operations. As is true
for all projects, the suspended projects are reviewed for impairment whenever
there is an indication of potential reduction in a project's fair value.
Further, if it is determined that it is no longer probable that the projects
will be completed and all capitalized costs recovered through future operations,
the carrying values of the projects would be written down to the recoverable
value. These projects would bring on line approximately 2,938 and 3,418 MW of
base load and base load with peaking capacity, respectively. The estimated cost
to complete these projects is approximately $1.4 billion.
Projects in Early Development - Costs for projects that are in early stages
of development are capitalized only when it is highly probable that such costs
are ultimately recoverable and significant project milestones are achieved.
Until then, all costs, including interest costs are expensed. The projects in
early development with capitalized costs relate to three projects and include
geothermal drilling costs and equipment purchases.
Other Capital Projects - Other capital projects primarily consist of
enhancements to operating power plants, oil and gas and geothermal resource and
facilities development as well as software developed for internal use.
Unassigned Equipment - As of September 30, 2003, we had made progress
payments on 7 turbines, 1 heat recovery steam generator, and other equipment
with an aggregate carrying value of $117.8 million. This unassigned equipment is
classified on the balance sheet as other assets, because it is not assigned to
specific development and construction projects. We are holding this equipment
for potential use on future projects. It is possible that some of this
unassigned equipment may eventually be sold, potentially in combination with our
engineering and construction services. For equipment that is not assigned to
development or construction projects, interest is not capitalized.
Impairment Evaluation - All construction and development projects,
including unassigned turbines are reviewed for impairment whenever there is an
indication of potential reduction in a project's fair value. Equipment assigned
to such projects is not evaluated for impairment separately, as it is integral
to the assumed future operations of the project to which it is assigned. If it
-57-
is determined that it is no longer probable that the projects will be completed
and all capitalized costs recovered through future operations, the carrying
values of the projects would be written down to the recoverable value in
accordance with the provisions of FASB 144 "Accounting for Impairment or
Disposal of Long-Lived Assets." We review our other unassigned the equipment for
potential impairment based on probability-weighted alternatives of utilizing it
for future projects versus selling it. Utilizing this methodology, we do not
believe that the equipment not committed to sale is impaired. However, during
the second quarter of 2003, we recorded approximately $17.2 million in losses in
connection with the sale of two turbines, and we may incur further losses should
we decide to sell more unassigned equipment in the future.
Capital Availability and Liquidity-Enhancing Program -Access to capital for
many in the energy sector, including us, has been restricted since late 2001.
While we were able in the first half of 2002 and again in 2003 to access the
capital and bank credit markets, in this new environment, it was on
significantly different terms than in the past. In particular, our senior
working capital facility as well as our non-convertible debt issuances have been
secured by certain of our assets and equity interests. 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.
We are nearing the successful completion of our 2003 liquidity program. In
2003 we have closed approximately $2.1 billion of liquidity-enhancing
transactions. Over the past several months, we have:
o Completed an offering of approximately $301.7 million of Gilroy Energy
Center, LLC ("GEC") 4% Senior Secured Notes Due 2011;
o Completed a $230 million, non-recourse project financing for our
600-megawatt Riverside Energy Center, currently under construction in
Beloit, Wisconsin;
o Closed the initial public offering of Calpine Natural Gas Trust ("CNG
Trust"). CNG Trust acquired select Canadian natural gas and crude oil
properties from Calpine, generating net proceeds of approximately Cdn
$207.9 million (US$157.1 million);
o Sold a 70% interest in our 150-megawatt Auburndale, Florida power
plant for $88.0 million. We will hold the remaining 30% interest and
continue to operate and maintain the plant; and
o Received approximately Cdn$19.2 million (approximately US$14.7) from
the exercise of Warranted Units issued as part of the Calpine Power
Income Fund secondary offering.
o Completed a $140 million, 15-year, non-recourse term loan for our Blue
Spruce Energy Center. Funds from this new term loan were used to repay
the outstanding balance under our $106 million non-recourse project
financing for this facility.
The last significant transaction included in the 2003 liquidity program is
the non-recourse project financing to fund the construction of the 600-megawatt
Rocky Mountain Energy Center in Colorado. This financing is expected to close by
December 31, 2003.
In what has been a challenging year in the U.S. capital markets, we have
completed $4.6 billion of capital market transactions. Proceeds from these
financings have been used to refinance and repurchase existing debt. Most
recently we have:
o Closed the $800 million financing at our wholly owned subsidiaries,
Calpine Construction Finance Company, L.P. ("CCFC I") and CCFC Finance
Corp.;
o Priced an offering of $ 400 million of Second Priority Senior Secured
Notes due 2011, expected to close on November 18, 2003, and an
offering of $600 million Senior Unsecured Convertible Notes due 2023,
expected to close on November 14, 2003. We have granted the initial
purchaser an option to purchase an additional $300 million of the
senior unsecured convertible notes.
o Year to date, we have repurchased approximately $1.4 billion in
principal amount of our outstanding debt and preferred securities in
exchange for approximately $1.0 billion in cash and 30.0 million
shares of common stock valued at approximately $160.6 million. As a
result of these transactions, we have realized a net pre-tax gain on
the repurchase of securities of approximately $202.4 million.
Credit Considerations - On July 17, 2003, Standard & Poor's placed our
corporate rating (currently rated at B), our senior unsecured debt rating
(currently at CCC+), our preferred stock rating (currently at CCC), our bank
loan rating (currently at B), and our second priority senior secured debt rating
(currently at B) under review for possible downgrade.
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On July 23, 2003, Fitch, Inc. downgraded our long-term senior unsecured
debt rating from B+ to B- (with a stable outlook), our preferred stock rating
from B- to CCC (with a stable outlook), and initiated coverage of our senior
secured debt rating at BB- (with a stable outlook).
On October 20, 2003, Moody's downgraded the rating of our long-term senior
unsecured debt from B1 to Caa1 (with a stable outlook) and our senior implied
rating from Ba3 to B2 (with a stable outlook). The ratings on our senior
unsecured debt, senior unsecured convertible debt and convertible preferred
securities were also lowered (with a stable outlook). The Moody's downgrade does
not impact our credit agreements, and we continue to conduct our business with
our usual creditworthy counterparties.
Performance Metrics
We believe that certain non-GAAP financial measures and other performance
metrics are particularly important in understanding our business. These are
described below, beginning with the non-GAAP financial measures:
o Average gross profit margin based on non-GAAP revenue and non-GAAP
cost of revenue. A high percentage of our revenue consists of CES
hedging, balancing and optimization activity undertaken primarily to
enhance the value of our generating assets. 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 (non-trading 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 and that pursuant to EITF No.
02-3, trading activity is now shown net in our Statements of
Operations under mark-to-market activity, 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 for hedging and optimization with purchased power
expense for hedging and optimization 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 for hedging and optimization with purchased gas
expense for hedging and optimization 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.
Other performance metrics are described below and are important to
understanding the degree to which our generating assets are productively
employed, how efficiently they operate, and how market forces in the electricity
and gas markets and our risk management activities affect our profitability. We
elaborate below on why each of these metrics is useful in understanding our
business.
o Average availability and average baseload capacity factor or operating
rate. Availability represents the percent of total hours during the
period that our plants were available to run after taking into account
the downtime associated with both scheduled and unscheduled outages.
The baseload capacity factor, sometimes called operating rate, is
calculated by dividing (a) total baseload megawatt hours generated by
our power plants (excluding pure peaker facilities ("peakers")) by the
product of multiplying (b) the weighted average baseload megawatts in
operation during the period by (c) the total hours in the period. The
baseload capacity factor is thus a measure of total actual baseload
generation as a percent of total potential baseload generation. If we
elect not to generate during periods when electricity pricing is too
low or gas prices too high to operate profitably, the baseload
capacity factor will reflect that decision as well as both scheduled
and unscheduled outages due to maintenance and repair requirements.
Peakers are designed to operate infrequently, generally only during
periods of high demand, and so are excluded from the calculation of
baseload capacity factor.
-59-
o Average heat rate for gas-fired fleet of power plants expressed in
British Thermal Units ("Btu") of fuel consumed per KWh generated. We
calculate the average heat rate for our gas-fired power plants
(excluding peakers) by dividing (a) fuel consumed in Btu's by (b) KWh
generated. The resultant heat rate is a measure of fuel efficiency, so
the lower the heat rate, the better. We also calculate a
"steam-adjusted" heat rate, in which we adjust the fuel consumption in
Btu's down by the equivalent heat content in steam or other thermal
energy exported to a third party, such as to steam hosts for our
cogeneration facilities. Our goal is to have the lowest average heat
rate in the industry.
o Average all-in realized electric price expressed in dollars per MWh
generated. Our risk management and optimization activities are
integral to our power generation business and directly impact our
total realized revenues from generation. Accordingly, we calculate the
all-in realized electric price per MWh generated by dividing (a)
adjusted electricity and steam revenue, which includes capacity
revenues, energy revenues, thermal revenues and the spread on sales of
purchased electricity for hedging, balancing, and optimization
activity, by (b) total generated MWh in the period.
o Average cost of natural gas expressed in dollars per millions of Btu's
of fuel consumed. Our risk management and optimization activities
related to fuel procurement directly impact our total fuel expense.
The fuel costs for our gas-fired power plants are a function of the
price we pay for fuel purchased and the results of the fuel hedging,
balancing, and optimization activities by CES. Accordingly, we
calculate the cost of natural gas per millions of Btu's of fuel
consumed in our power plants by dividing (a) adjusted fuel expense
which includes the cost of fuel consumed by our plants (adding back
cost of 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. We also calculate average spark spread
per MWh as adjusted for the margin on equity gas production. We
calculate the margin on equity gas production by adding (a) oil and
gas sales plus (b) the value of equity gas eliminated from fuel
expense in consolidation and subtracting from this sum both (c) oil
and gas production expense and (d) the depreciation, depletion and
amortization expense attributable to oil and gas production. This
amount is divided by (e) total generated MWh in the period and the
resultant value per MWh is added to average spark spread. Because of
our strategy of partially hedging our fuel expense exposure for
electric generation with our equity gas production, we believe that
this equity-gas-adjusted spark spread value is the more meaningful
measure of spark spread in evaluating our performance.
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.
-60-
Non-GAAP Netted
GAAP Presentation Presentation
Three Months Ended Three Months Ended
September 30, September 30,
---------------------------- -----------------------------
2003 2002 2003 2002
------------- ------------ ------------- -------------
Restated (1)
(In thousands)
Revenue, Cost of Revenue and Gross Profit
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue (4)................. $ 1,440,056 $ 943,177 $ 1,447,177 $ 1,161,856
Sales of purchased power for hedging and
optimization (4)................................ 843,013 1,278,520 -- --
------------- ------------ ------------- -------------
Total electric generation and marketing revenue...... 2,283,069 2,221,697 1,447,177 1,161,856
Oil and gas production and marketing revenue
Oil and gas sales................................. 27,879 21,827 27,879 21,827
Sales of purchased gas for hedging and
optimization (4)................................ 305,706 231,893 -- --
------------- ------------ ------------- -------------
Total oil and gas production and marketing revenue... 333,585 253,720 27,879 21,827
Mark-to-market activities, net
Realized gain (loss) on power and gas
transactions, net............................... (93) 6,845 (93) 6,845
Unrealized gain (loss) on power and gas
transactions, net............................... (10,930) (10,957) (10,930) (10,957)
------------- ------------ ------------- -------------
Total mark-to-market activities, net................. (11,023) (4,112) (11,023) (4,112)
Other revenue........................................ 81,496 3,393 81,496 3,393
------------- ------------ ------------- -------------
Total revenue................................... 2,687,127 2,474,698 1,545,529 1,182,964
------------- ------------ ------------- -------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense........................... 185,091 141,170 185,091 141,170
Royalty expense................................... 7,022 4,743 7,022 4,743
Purchased power expense for hedging and
optimization (2)................................ 835,892 1,059,841 -- --
------------- ------------ ------------- -------------
Total electric generation and marketing expense...... 1,028,005 1,205,754 192,113 145,913
Oil and gas production and marketing expense
Oil and gas operating expense..................... 24,575 22,953 24,575 22,953
Purchased gas expense for hedging and
optimization (2)................................ 293,241 218,443 -- --
------------- ------------ ------------- -------------
Total oil and gas production and marketing expense... 317,816 241,396 24,575 22,953
Fuel expense......................................... 800,270 525,478 787,805 512,028
Depreciation, depletion and amortization expense..... 148,063 121,667 148,063 121,667
Operating lease expense.............................. 28,439 28,497 28,439 28,497
Other cost of revenue................................ 8,380 1,354 8,380 1,354
------------- ------------ ------------- -------------
Total cost of revenue........................... 2,330,973 2,124,146 1,189,375 832,412
Gross profit...................................... $ 356,154 $ 350,552 $ 356,154 $ 350,552
============= ============ ============= =============
Gross profit margin............................... 13.3% 14.2% 23.0% 29.6%
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Non-GAAP Netted
GAAP Presentation Presentation
Nine Months Ended Nine Months Ended
September 30, September 30,
---------------------------- -----------------------------
2003 2002 2003 2002
------------- ------------ ------------- -------------
Restated (1)
(In thousands)
Revenue, Cost of Revenue and Gross Profit
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue (4)................. $ 3,634,730 $ 2,272,889 $ 3,649,272 $ 2,749,661
Sales of purchased power for hedging and
optimization (4)................................ 2,269,102 2,516,727 -- --
------------- ------------ ------------- -------------
Total electric generation and marketing revenue...... 5,903,832 4,789,616 3,649,272 2,749,661
Oil and gas production and marketing revenue
Oil and gas sales................................. 83,358 91,031 83,358 91,031
Sales of purchased gas for hedging and
optimization (4)................................ 961,652 664,649 -- --
------------- ------------ ------------- -------------
Total oil and gas production and marketing revenue... 1,045,010 755,680 83,358 91,031
Mark-to-market activities, net
Realized gain (loss) on power and gas
transactions, net............................... 30,180 15,276 30,180 15,276
Unrealized gain (loss) on power and gas
transactions, net............................... (18,921) (6,166) (18,921) (6,166)
------------- ------------ ------------- -------------
Total mark-to-market activities, net................. 11,259 9,110 11,259 9,110
Other revenue........................................ 97,596 9,371 97,596 9,370
------------- ------------ ------------- -------------
Total revenue................................... 7,057,697 5,563,777 3,841,485 2,859,172
------------- ------------ ------------- -------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense........................... 514,518 376,058 514,518 376,058
Royalty expense................................... 18,840 13,092 18,840 13,092
Purchased power expense for hedging and
optimization (4)................................ 2,254,560 2,039,955 -- --
------------- ------------ ------------- -------------
Total electric generation and marketing expense...... 2,787,918 2,429,105 533,358 389,150
Oil and gas production and marketing expense
Oil and gas operating expense..................... 79,348 67,380 79,348 67,380
Purchased gas expense for hedging and
optimization (4)................................ 941,312 671,196 -- --
------------- ------------ ------------- -------------
Total oil and gas production and marketing expense... 1,020,660 738,576 79,348 67,380
Fuel expense......................................... 2,005,874 1,208,310 1,985,534 1,214,856
Depreciation, depletion and amortization expense..... 422,960 320,310 422,960 320,310
Operating lease expense.............................. 84,298 84,877 84,298 84,877
Other cost of revenue................................ 20,501 4,452 20,501 4,452
------------- ------------ ------------- -------------
Total cost of revenue........................... 6,342,211 4,785,630 3,125,999 2,081,025
Gross profit...................................... $ 715,486 $ 778,147 $ 715,486 $ 778,147
============= ============ ============= =============
Gross profit margin............................... 10.1% 14.0% 18.6% 27.2%
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Non-GAAP Netted Non-GAAP Netted
Presentation Presentation
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- -----------------------------
2003 2002 2003 2002
------------- ------------ ------------- -------------
Restated (1)
(In thousands)
Other Non-GAAP Performance Metrics Average availability
and baseload capacity factor:
Average availability................................. 98% 91% 94% 92%
Average baseload capacity factor:
Average total MW in operation........................ 21,821 16,299 19,874 13,456
Less: Average MW of pure peakers..................... 2,888 1,980 2,599 1,613
Average baseload MW in operation..................... 18,933 14,319 17,275 11,843
Hours in the period.................................. 2,208 2,208 6,552 6,552
Potential baseload generation........................ 41,804 31,616 113,186 77,595
Actual total generation.............................. 25,882 23,375 63,213 53,809
Less: Actual pure peakers' generation................ 766 658 1,077 989
Actual baseload generation........................... 25,116 22,717 62,136 52,820
Average baseload capacity factor..................... 60% 72% 55% 68%
Average heat rate for gas-fired power plants (excluding
peakers) (Btu's/kWh):
Not steam adjusted................................... 7,815 7,646 7,910 7,937
Steam adjusted....................................... 7,160 7,077 7,201 7,267
Average all-in realized electric price:
Adjusted electricity and steam revenue
(in thousands)..................................... $ 1,447,177 $ 1,161,856 $ 3,649,272 $ 2,749,661
MWh generated (in thousands)......................... 25,882 23,375 63,213 53,809
Average all-in realized electric price per MWh....... $ 55.91 $ 49.71 $ 57.73 $ 51.10
Average cost of natural gas:
Cost of oil and natural gas burned by power plants
(in thousands)..................................... $ 787,805 $ 512,028 $ 1,985,534 $ 1,214,856
Fuel cost elimination................................ 85,275 46,957 292,070 116,911
------------- ------------ ------------- -------------
Adjusted fuel expense................................ $ 873,080 $ 558,984 $ 2,277,604 $ (33,176)
Million Btu's ("MMBtu") of fuel consumed by
generating plants (in thousands)................... 172,707 158,552 423,159 377,694
Average cost of natural gas per MMBtu................ $ 5.06 $ 3.53 $ 5.38 $ 3.53
MWh generated (in thousands)......................... 25,882 23,375 63,213 53,809
Average cost of adjusted fuel expense per MWh........ $ 33.73 $ 23.91 $ 36.03 $ 24.75
Equity gas contribution margin:
Oil and gas sales.................................... 27,879 21,827 83,358 91,031
Add: Fuel cost eliminated in consolidation........... 85,275 46,957 292,070 116,911
------------- ------------ ------------- -------------
Subtotal.......................................... 113,154 68,784 375,428 207,942
Less: Oil and gas operating expense.................. 24,575 22,953 79,348 67,380
Less: Depletion, depreciation and amortization....... 39,496 35,976 117,591 108,905
------------- ------------ ------------- -------------
Equity gas contribution margin....................... 49,083 9,885 178,489 31,657
MWh generated (in thousands)......................... 25,882 23,375 63,213 53,809
Equity gas contribution margin per MWh............... 1.90 0.42 2.82 0.59
Average spark spread:
Adjusted electricity and steam revenue
(in thousands)..................................... $ 1,447,177 $ 1,161,856 $ 3,649,272 $ 2,749,661
Less: Adjusted fuel expense (in thousands)........... $ 873,080 $ 558,984 $ 2,277,604 $ 1,331,767
------------- ------------ ------------- -------------
Spark spread (in thousands)....................... $ 574,097 $ 602,873 $ 1,371,668 $ 1,417,895
MWh generated (in thousands)......................... 25,882 23,375 63,213 53,809
Average spark spread per MWh......................... $ 22.18 $ 25.79 $ 21.70 $ 26.35
Add: Equity gas contribution......................... 49,083 9,855 178,489 31,657
Spark spread with equity gas benefits
(in thousands)..................................... 623,180 612,728 1,550,157 1,449,552
Average spark spread with equity gas
benefits per MWh................................... 24.08 26.21 24.52 26.94
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The tables below provide additional detail of total mark-to-market
activity. For the three and nine months ended September 30, 2003 and 2002,
mark-to-market activity, net consisted of (dollars in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- -----------------------------
2003 2002 2003 2002
------------- ------------ ------------- -------------
Restated (1) Restated (1)
Mark-to-market activity, net
Realized:
Power activity
"Trading Activity" as defined in EITF No. 02-03... $ 8,581 $ 2,329 $ 33,243 $ 3,305
Ineffectiveness related to cash flow hedges....... -- -- -- --
Other mark-to-market activity (3)................. (8,935) -- (8,935) --
------------- ------------ ------------- -------------
Total realized power activity................... $ (354) $ 2,329 $ 24,308 $ 3,305
============= ============ ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03... $ 261 $ 4,516 $ 5,872 $ 11,971
Ineffectiveness related to cash flow hedges....... -- -- -- --
Other mark-to-market activity (3)................. -- -- -- --
------------- ------------ ------------- -------------
Total realized gas activity..................... $ 261 $ 4,516 $ 5,872 $ 11,971
============= ============ ============= =============
Total realized activity:
"Trading Activity" as defined in EITF No. 02-03...... $ 8,842 $ 6,845 $ 39,115 $ 15,276
Ineffectiveness related to cash flow hedges.......... -- -- -- --
Other mark-to-market activity (3).................... (8,935) -- (8,935) --
------------- ------------ ------------- -------------
Total realized activity....................... $ (93) $ 6,845 $ 30,180 $ 15,276
============= ============ ============= =============
Unrealized:
Power activity
"Trading Activity" as defined in EITF No. 02-03... $ (15,920) $ 14,130 $ (29,031) $ 25,410
Ineffectiveness related to cash flow hedges....... (115) (3,072) (4,753) (4,297)
Other mark-to-market activity (3)................. (1,087) -- (1,087) --
------------- ------------ ------------- -------------
Total unrealized power activity................. $ (17,122) $ 11,058 $ (34,871) $ 21,113
============= ============ ============= =============
Gas activity
"Trading Activity" as defined in EITF No. 02-03... $ 10,562 $ (19,874) $ 12,140 $ (30,902)
Ineffectiveness related to cash flow hedges....... (4,370) (2,141) 3,810 3,623
Other mark-to-market activity (3)................. -- -- -- --
------------- ------------ ------------- -------------
Total unrealized gas activity................... $ 6,192 $ (22,015) $ 15,950 $ (27,279)
============= ============ ============= =============
Total Unrealized activity:
"Trading Activity" as defined in EITF No. 02-03...... $ (5,358) $ (5,744) $ (16,891) $ (5,492)
Ineffectiveness related to cash flow hedges.......... (4,485) 5,213 (943) (674)
Other mark-to-market activity (3).................... (1,087) -- (1,087) --
------------- ------------ ------------- -------------
Total unrealized activity..................... $ (10,930) $ (10,957) $ (18,921) $ (6,166)
============= ============ ============= =============
Total mark-to-market activity:
"Trading Activity" as defined in EITF No. 02-03...... $ 3,484 $ 1,101 $ 22,224 $ 9,784
Ineffectiveness related to cash flow hedges.......... (4,485) (5,213) (943) (674)
Other mark-to-market activity (3).................... (10,022) -- (10,022) --
------------- ------------ ------------- -------------
Total mark-to-market activity.............. $ (11,023) $ (4,112) $ 11,259 $ 9,110
============= ============ ============= =============
- ------------
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
(2) For the three and nine months ended September 30, 2003 and 2002, the
unrealized mark-to-market gains and losses shown above include hedge
ineffectiveness as discussed in Note 8 of the Notes to Consolidated
Condensed Financial Statements.
(3) Activity related to our assets but does not qualify for hedge accounting.
(4) Following is a reconciliation of GAAP to non-GAAP presentation further to
the narrative set forth under this Performance Metrics section: ($ in
thousands)
-64-
To Net
Hedging,
Balancing & Netted
GAAP Optimization Non-GAAP
Balance Activity Balance
------------- ------------ -------------
Three months ended September 30, 2003
Electricity and steam revenue............................ $ 1,440,056 $ 7,121 $ 1,447,177
Sales of purchased power for hedging and optimization.... 843,013 (843,013) --
Sales of purchased gas for hedging and optimization...... 305,706 (305,706) --
Purchased power expense for hedging and optimization..... 835,892 (835,892) --
Purchased gas expense for hedging and optimization....... 293,241 (293,241) --
Fuel expense............................................. 800,270 (12,465) 787,805
Three months ended September 30, 2002, Restated (1)
Electricity and steam revenue............................ $ 943,177 $ 218,679 $ 1,161,856
Sales of purchased power for hedging and optimization.... 1,278,520 (1,278,520) --
Sales of purchased gas for hedging and optimization...... 231,893 (231,893) --
Purchased power expense for hedging and optimization..... 1,059,841 (1,059,841) --
Purchased gas expense for hedging and optimization....... 218,443 (218,443) --
Fuel expense............................................. 525,478 (13,450) 512,028
To Net
Hedging,
Balancing & Netted
GAAP Optimization Non-GAAP
Balance Activity Balance
------------- ------------ -------------
Nine months ended September 30, 2003
Electricity and steam revenue............................ $ 3,634,730 $ 14,542 $ 3,649,272
Sales of purchased power for hedging and optimization.... 2,269,102 (2,269,102) --
Sales of purchased gas for hedging and optimization...... 961,652 (961,652) --
Purchased power expense for hedging and optimization..... 2,254,560 (2,254,560) --
Purchased gas expense for hedging and optimization....... 941,312 (941,312) --
Fuel expense............................................. 2,005,874 (20,340) 1,985,534
Nine months ended September 30, 2002, Restated (1)
Electricity and steam revenue............................ $ 2,272,889 $ 476,772 $ 2,749,661
Sales of purchased power for hedging and optimization.... 2,516,727 (2,516,727) --
Sales of purchased gas for hedging and optimization...... 664,649 (664,649) --
Purchased power expense for hedging and optimization..... 2,039,955 (2,039,955) --
Purchased gas expense for hedging and optimization....... 671,196 (671,196) --
Fuel expense............................................. 1,208,310 6,546 1,214,856
- ------------
(1) See Note 2 of the Notes to Consolidated Condensed Financial Statements
regarding the restatement of financial statements.
Overview
Summary of Key Activities
Finance - New Issuances
Date Amount Description
- ---------- ------------------------ ----------------------------------------
7/03 $3.3 billion Completed an offering in a private
placement under Rule 144A comprised
of a $750.0 million floating rate
term loan, $500.0 million of Second
Priority Senior Secured Floating
Rate Notes due 2007, $1.15 billion
of 8.5% Second Priority Senior
Secured Notes due 2010, and $900.0
million of 8.75% Second Priority
Senior Secured Notes due 2013.
7/03 $500.0 million Closed a $300.0 million two-year
working capital revolver and a
$200.0 million four-year term loan.
7/03 $200.0 million Entered into a cash collateralized
letter of credit facility for up to
$200.0 million, which can be issued
through July 15, 2005.
-65-
Date Amount Description
- ---------- ------------------------ ----------------------------------------
8/03 $750.0 million CCFCI and CCFC Finance Corp. completed
an offering of $385.0 million First
Priority Floating Rate Secured
Institutional Term Loans Due 2009 at
98% of par as well as $365.0 million
of Second Priority Secured Floating
Rate Notes Due 2011 at 98.01% of
par.
8/03 $230.0 million Completed a $230.0 million non-recourse
project financing for Riverside
Energy Center.
9/03 $50.0 million CCFCI and CCFC Finance Corp. completed
an additional $50.0 million of
Second Priority Senior Secured
Floating Rate Notes Due 2011 at 99%
of par.
9/03 $301.7 million GEC completed an offering in a private
placement under Rule 144A for $301.7
million of 4% Senior Secured Notes
Due 2011.
9/03 $74.0 million Received funding on a third party
preferred equity investment in
GEC Holdings, LLC, totaling
approximately $74.0 million.
Finance - Repurchases/Repayments
Date Amount Description
- ---------- ------------------------ ----------------------------------------
7/03 $949.6 million Repaid the remaining $949.6 million in
funded balance outstanding under our
$1.0 billion secured term credit
facility.
7/03 $555.5 million Repaid the $555.5 million outstanding
balance on our revolving credit
facilities.
7/03 $50.0 million Repaid the remaining $50.0 million
outstanding balance on our peaker
financing.
8/03 $880.1 million Repaid the remaining $880.1 million
outstanding balance on our CCFC I
project financing.
7/03-9/03 $1.2 billion Repurchased $1.2 billion in aggregate
outstanding principal amount of
various debt securities at a
redemption price of $992.1 million
plus accrued interest to the
redemption date. We recorded a net
pre-tax gain on these transactions
of $185.1 million.
9/03 $157.5 million Exchanged $157.5 million in aggregate
outstanding debt securities and HIGH
TIDES for 25.2 million shares of our
common stock in privately negotiated
transactions. We recorded a net
pre-tax gain on these transactions
of $22.6million.
Other:
Date Description
---------- -----------------------------------------------------
7/03 S&P placed our corporate rating (currently rated at
B), our senior unsecured debt rating (currently at
CCC+), our preferred stock rating (currently at
CCC), our bank loan rating (currently at B) and
our second priority senior secured debt rating
(currently at B) under review for possible
downgrade.
7/03 Fitch, Inc. downgraded our long-term senior unsecured
debt rating from B+ to B- (with a stable outlook),
our preferred stock rating from B- to CCC (with a
stable outlook), and initiated coverage of our
senior secured debt rating at BB- (with a stable
outlook).
-66-
Date Description
---------- -----------------------------------------------------
8/03 Received $69.4 million payment for final settlement
with Enron.
9/03 Completed sale of a 70-percent interest in Auburndale
Power Plant to Pomifer Power Funding, LLC, a
subsidiary of ArcLight Energy Partners Fund 1,
L.P., for $86.0 million in cash.
California Power Market - See Note 14 of the Notes to Consolidated Condensed
Financial Statements regarding the California Power Market.
Financial Market Risks
Because we are primarily focused on generation of electricity using
gas-fired turbines, our natural physical commodity position is "short" fuel
(i.e., natural gas consumer) and "long" power (i.e., electricity seller). To
manage forward exposure to price fluctuation in these and (to a lesser extent)
other commodities, we enter into derivative commodity instruments.
The change in fair value of outstanding commodity derivative instruments
from January 1, 2003 through September 30, 2003, is summarized in the table
below (in thousands):
Fair value of contracts outstanding at January 1, 2003.......... $ 150,627
Gains recognized or otherwise settled during the period (1)..... (106,099)
Changes in fair value attributable to changes in valuation
techniques and assumptions.................................... --
Changes in fair value attributable to new contracts............. 67,636
Changes in fair value attributable to price movements........... 103,633
Terminated derivatives (2)...................................... (55,120)
Other changes in fair value..................................... 160
-------------
Fair value of contracts outstanding at September 30, 2003 (3)... $ 160,837
============
- ------------
(1) Recognized gains from commodity cash flow hedges of $75.9 million
(represents realized value of cash flow hedge activity of $(54.2) million
as disclosed in Note 8 of the Notes to Consolidated Condensed Financial
Statements, net of terminated derivatives of $(130.1) million) and $30.2
million realized gain on mark-to-market activity, which is reported in the
Statement of Operations under mark-to-market activities, net.
(2) Includes the value of derivatives terminated or 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 Condensed Financial Statements
The fair value of outstanding derivative commodity instruments at September
30, 2003, based on price source and the period during which the instruments will
mature, are summarized in the table below (in thousands):
Fair Value Source 2003 2004-2005 2006-2007 After 2007 Total
- ------------------------------------------------- ----------- ----------- ----------- ----------- ----------
Prices actively quoted.............................. $ 45,572 $ 33,687 $ -- $ -- $ 79,259
Prices provided by other external sources........... 42,012 26,696 31,871 17,496 118,075
Prices based on models and other valuation methods.. -- (4,634) (6,074) (25,789) (36,497)
---------- ---------- ---------- ----------- ----------
Total fair value.................................... $ 87,584 $ 55,749 $ 25,797 $ (8,293) $ 160,837
========== ========== ========== =========== ==========
Our risk managers maintain fair value price information derived from
various sources in our risk management systems. The propriety of that
information is validated by our Risk Control group. Prices actively quoted
include validation with prices sourced from commodities exchanges (e.g., New
York Mercantile Exchange). Prices provided by other external sources include
quotes from commodity brokers and electronic trading platforms. Prices based on
models and other valuation methods are validated using quantitative methods.
-67-
The counterparty credit quality associated with the fair value of
outstanding derivative commodity instruments at September 30, 2003, and the
period during which the instruments will mature are summarized in the table
below (in thousands):
Credit Quality 2003 2004-2005 2006-2007 After 2007 Total
---------- ----------- ----------- ----------- -----------
(based on September 30, 2003, ratings)
- -------------------------------------------
Investment grade.................................... $ 54,503 $ 39,609 $ 28,486 $ (8,293) $ 114,305
Non-investment grade................................ 32,801 16,140 (2,689) -- 46,252
No external ratings................................. 280 -- -- -- 280
---------- ---------- ---------- ----------- ----------
Total fair value.................................... $ 87,584 $ 55,749 $ 25,797 $ (8,293) $ 160,837
========== ========== ========== =========== ==========
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, 2003:
Crude oil............................ $ (708) $ (972)
Electricity.......................... 61,161 (49,284)
Natural gas.......................... 100,384 21,749
------------ -------------
Total............................. $ 160,837 $ (28,507)
============ =============
Derivative commodity instruments included in the table are those included
in Note 8 of the Notes to Consolidated Condensed Financial Statements. The fair
value of derivative commodity instruments included in the table is based on
present value adjusted quoted market prices of comparable contracts. The fair
value of electricity derivative commodity instruments after a 10% adverse price
change includes the effect of increased power prices versus our derivative
forward commitments. Conversely, the fair value of the natural gas derivatives
after a 10% adverse price change reflects a general decline in gas prices versus
our derivative forward commitments. Derivative commodity instruments offset the
price risk exposure of our physical assets. None of the offsetting physical
positions are included in the table above.
Price changes were calculated by assuming an across-the-board ten percent
adverse price change regardless of term or historical relationship between the
contract price of an instrument and the underlying commodity price. In the event
of an actual ten percent change in prices, the fair value of our derivative
portfolio would typically change by more than ten percent for earlier forward
months and less than ten percent for later forward months because of the higher
volatilities in the near term and the effects of discounting expected future
cash flows.
The primary factors affecting the fair value of our derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and MWh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions decreased 66%
from December 31, 2002, to September 30, 2003, and the total volume of open
power derivative positions decreased 176% for the same period. In that prices
for electricity and natural gas are among the most volatile of all commodity
prices, there may be material changes in the fair value of our derivatives over
time, driven both by price volatility and the changes in volume of open
derivative transactions. Under SFAS No. 133, the change since the last balance
sheet date in the total value of the derivatives (both assets and liabilities)
is reflected either in Other Comprehensive Income ("OCI"), net of tax, or in the
statement of operations as an item (gain or loss) of current earnings. As 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, 2003, have reflected this. See Notes 8 and 9 of the Notes to
Consolidated Condensed Financial Statements for additional information on
derivative activity and OCI.
Collateral Debt Securities - These securities primarily support the King
City operating lease and 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 effect on the value of the securities
at the maturity date. The securities are recorded at an amortized cost of $81.5
million at September 30, 2003. The following tables present our different
classes of collateral debt securities by face value at expected maturity date
and also by fair market value as of September 30, 2003, (dollars in thousands):
-68-
Weighted
Average
Interest Rate 2004 2005 2006 2007 Thereafter Total
------------- ------ ------ ------ ------ ---------- --------
Corporate Debt Securities............. 7.3% $6,050 $7,825 $ -- $ -- $ -- $ 13,875
U.S. Treasury Notes................... 6.5% -- 1,975 -- -- -- 1,975
U.S. Treasury Securities
(non- interest bearing)............. -- -- -- 9,700 9,100 96,150 114,950
------ ------ ------ ------ ------- --------
Total.............................. $6,050 $9,800 $9,700 $9,100 $96,150 $130,800
====== ====== ====== ====== ======= ========
Fair Market Value
-----------------
Corporate Debt Securities.................................. $ 14,659
U.S. Treasury Notes........................................ 2,161
U.S. Treasury Securities (non-interest bearing)............ 82,489
---------
Total................................................... $ 99,309
=========
Interest Rate Swaps and Cross Currency Swaps - From time to time, we use
interest rate swap agreements to mitigate our exposure to interest rate
fluctuations associated with certain of our debt instruments. We do not use
interest rate swap agreements for speculative or trading purposes. The following
tables summarize the fair market values of our existing interest rate swap
agreements as of September 30, 2003, (dollars in thousands):
Weighted Average Weighted Average
Notional Interest Rate
Maturity Date Principal Amount (Pay) Interest Rate (Receive) Fair Market Value
- ---------------- ----------------- ---------------- ------------------------- --------------------
2008............ $ 106,294 4.2% 3-month US$ LIBOR $ (5,216)
2011............ 44,175 6.9% 3-month US$ LIBOR (6,770)
2012............ 112,455 6.5% 3-month US$ LIBOR (17,652)
2014............ 61,781 6.7% 3-month US$ LIBOR (9,151)
----------- -----------
Total........ $ 324,705 5.8% $ (38,789)
=========== ===========
Debt financing - Because of the significant capital requirements within our
industry, debt financing is often needed to fund our growth. Certain debt
instruments may affect us adversely because of changes in market conditions. We
have used two primary forms of debt which are subject to market risk: (1)
Variable rate construction/project financing; (2) Other variable-rate
instruments. Significant LIBOR increases could have a negative impact on our
future interest expense. Our variable-rate construction/project financing is
primarily through Calpine Construction Finance Company II, LLC ("CCFC II").
Borrowings under this credit agreement are used exclusively to fund the
construction of our power plants. Other variable-rate instruments consist
primarily of our revolving credit and term loan facilities, which are used for
general corporate purposes. Both our variable-rate construction/project
financing and other variable-rate instruments are indexed to base rates,
generally LIBOR, as shown below.
-69-
The following table summarizes our variable-rate debt exposed to interest
rate risk as of September 30, 2003. All outstanding balances and fair market
values are shown net of applicable premium or discount, if any (dollars in
thousands):
Outstanding Weighted Average Fair Market
Balance Interest Rate Value
----------- ---------------- -----------
Variable-rate construction/project financing and
other variable-rate instruments:
Short-term
First Priority Senior Secured Term Loan B Notes
Due 2007........................................... $ 2,000 3-month US$LIBOR $ 2,000
First Priority Secured Institutional Term Loan Due
2009 (CCFC I)...................................... 3,812 (1) 3,812
Second Priority Senior Secured Term Loan B Notes
Due 2007........................................... 7,500 (2) 7,500
Second Priority Senior Secured Floating Rate
Notes Due 2007..................................... 5,000 (3) 5,000
------------ -----------
Total short-term.................................. $ 18,312 $ 18,312
============ ===========
Long-term
Blue Spruce Energy Center Project Financing.......... $ 103,147 1-month US$LIBOR $ 103,147
Riverside Energy Center Project Financing............ 133,207 1-month US$LIBOR 133,207
First Priority Secured Institutional Term Loan
Due 2009 (CCFC I).................................. 369,758 (1) 369,758
Second Priority Senior Secured Floating Rate Notes
Due 2011 (CCFC I).................................. 415,000 (1) 415,000
Corporate revolving line of credit................... -- 1-month US$LIBOR --
First Priority Senior Secured Term Loan B Notes
Due 2007..... .................................... 198,000 3-month US$LIBOR 198,000
Second Priority Senior Secured Floating Rate Notes
Due 2007........................................... 495,000 (3) 495,000
Second Priority Senior Secured Term Loan B Notes
Due 2007........................................... 742,500 (2) 742,500
Calpine Construction Finance Company II, LLC
(CCFC II).......................................... $ 2,167,910 1-month US$LIBOR $ 2,167,910
------------ -----------
Total long-term................................... $ 4,624,522 $ 4,624,522
------------ -----------
Total variable-rate construction/project financing and
other variable-rate instruments....................... $ 4,642,834 $ 4,642,834
============ ===========
- ------------
(1) British Bankers Association LIBOR Rate for deposit in US dollars for a
period of six months.
(2) U.S. prime rate in combination with the Federal Funds Effective Rate.
(3) British Bankers Association LIBOR Rate for deposit in US dollars for a
period of three months.
Construction/project financing facilities - In November 2004, the $2.5
billion secured construction financing revolving facility for our wholly owned
subsidiary CCFC II will mature, requiring us to refinance or extend this
indebtedness.
On August 14, 2003, our wholly owned subsidiaries, Calpine Construction
Finance Company, L.P. ("CCFC I") and CCFC Finance Corp., closed its $750 million
institutional term loans and secured notes offering, proceeds from which were
utilized to repay a majority of CCFC I's indebtedness which would have matured
in the fourth quarter of 2003. The offering included $385 million of First
Priority Secured Institutional Term Loans Due 2009 offered at 98% of par and
priced at LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points
and $365 million of Second Priority Senior Secured Floating Rate Notes Due 2011
offered at 98.01% of par and priced at LIBOR plus 850 basis points, with a LIBOR
floor of 125 basis points. S&P has assigned a B corporate credit rating to CCFC
I. S&P also assigned a B+ rating (with a negative outlook) to the First Priority
Secured Institutional Term Loans Due 2009 and a B- rating (with a negative
outlook) to the Second Priority Secured Floating Rate Notes Due 2011. The
noteholders' recourse is limited to seven of CCFC I's natural gas-fired electric
generating facilities located in various power markets in the United States, and
related assets and contracts.
-70-
On September 25, 2003, the Company's wholly owned subsidiaries, CCFC I and
CCFC Finance Corp., closed on a $50 million add-on financing to the $750 million
CCFC I offering completed on August 14, 2003.
Revolving credit and term loan facilities - On July 16, 2003, we closed our
$3.3 billion term loan and second-priority senior secured notes offering ("notes
offering"). The term loan and senior notes are secured by substantially all of
the assets owned directly by Calpine Corporation, including natural gas and
power plant assets and the stock of Calpine Energy Services and other
subsidiaries. The notes offering was comprised of two tranches of floating rate
securities and two tranches of fixed rate securities. The floating rate
securities included a $750 million, four-year term loan and a $500 million of
Second-Priority Senior Secured Floating Rate Notes due 2007. The fixed rate
securities included $1.15 billion of 8.5% Second Priority Senior Secured Notes
due 2010 and $900 million of 8.75% Second Priority Senior Secured Notes due
2013.
Concurrent with the notes offering, on July 16, 2003, we entered into
agreements for a new $500 million working capital facility. The new
first-priority senior secured facility consists of a two-year, $300 million
working capital revolver and a four-year, $200 million term loan that together
provide up to $500 million in combined cash borrowing and letter of credit
capacity. The new facility replaced our prior working capital facilities and is
secured by a first-priority lien on the same assets that collateralize our
recently completed notes offering.
New Accounting Pronouncements
In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 applies to fiscal years beginning after June 15,
2002, and amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies." This standard applies to legal obligations associated with
the retirement of long-lived assets that result from the acquisition,
construction, development or normal use of the assets and requires that a
liability for an asset retirement obligation be recognized when incurred,
recorded at fair value and classified as a liability in the balance sheet. When
the liability is initially recorded, the entity will capitalize the cost and
increase the carrying value of the related long-lived asset. Asset retirement
obligations represent future liabilities, and, as a result, accretion expense
will be accrued on this liability until the obligation is satisfied. At the same
time, the capitalized cost will be depreciated over the estimated useful life of
the related asset. At the settlement date, the entity will settle the obligation
for its recorded amount or recognize a gain or loss upon settlement.
We adopted the new rules on asset retirement obligations on January 1,
2003. As required by the new rules, we recorded liabilities equal to the present
value of expected future asset retirement obligations at January 1, 2003. We
identified obligations related to operating gas-fired power plants, geothermal
power plants and oil and gas properties. The liabilities are partially offset by
increases in net assets, net of accumulated depreciation, recorded as if the
provisions of SFAS 143 had been in effect at the date the obligation was
incurred, which for power plants is generally the start of commercial operations
for the facility.
Based on current information and assumptions, we recorded, as of January 1,
2003, an additional long-term liability of $25.9 million, an additional asset
within property, plant and equipment, net of accumulated depreciation, of $26.9
million, and a pre-tax gain to income due to the cumulative effect of a change
in accounting principle of $1.0 million. These entries include the effects of
the reversal of site dismantlement and restoration costs previously expensed in
accordance with SFAS No. 19.
In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities," which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (Including Certain
Costs Incurred in a Restructuring)." We have adopted, effective January 1, 2003,
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. SFAS No. 146 has not had a material impact on our
Consolidated Condensed Financial Statements.
In November 2002 the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). This Interpretation addresses
the disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under guarantees. In addition, the
Interpretation clarifies the requirements related to the recognition of a
liability by a guarantor at the inception of a guarantee for the obligations
-71-
that the guarantor has undertaken in issuing the guarantee. We adopted the
disclosure requirements of FIN 45 for the fiscal year ended December 31, 2002,
and the recognition provisions on January 1, 2003. Adoption of this
Interpretation did not have a material impact on our Consolidated Condensed
Financial Statements.
On January 1, 2003, we prospectively adopted the fair value method of
accounting for stock-based employee compensation pursuant to SFAS No. 123, as
amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition
and Disclosure" ("SFAS No. 148"). SFAS No. 148 amends SFAS No. 123 to provide
alternative methods of transition for companies that voluntarily change their
accounting for stock-based compensation from the less preferred intrinsic value
based method to the more preferred fair value based method. Prior to its
amendment, SFAS No. 123 required that companies enacting a voluntary change in
accounting principle from the intrinsic value methodology provided by Accounting
Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to
Employees" ("APB 25") could only do so on a prospective basis; no adoption or
transition provisions were established to allow for a restatement of prior
period financial statements. SFAS No. 148 provides two additional transition
options to report the change in accounting principle - the modified prospective
method and the retroactive restatement method. Additionally, SFAS No. 148 amends
the disclosure requirements of SFAS No. 123 to require prominent disclosures in
both annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on reported
results. We have elected to adopt the provisions of SFAS No. 123 on a
prospective basis; consequently, we are required to provide a pro-forma
disclosure of net income and earnings per share as if SFAS No. 123 accounting
had been applied to all prior periods presented within its financial statements.
Adoption of SFAS No. 123 has had a material impact on our financial statements.
See Note 2 of the Notes to Consolidated Condensed Financial Statements for more
information.
In January 2003 the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of ARB 51" ("FIN 46"). FIN 46
requires the consolidation of entities in which an enterprise absorbs a majority
of the entity's expected losses, receives a majority of the entity's expected
residual returns, or both, as a result of ownership, contractual or other
financial interest in the entity. Historically, entities have generally been
consolidated by an enterprise when it has a controlling financial interest
through ownership of a majority voting interest in the entity. The objectives of
FIN 46 are to provide guidance on the identification of Variable Interest
Entities ("VIE") for which control is achieved through means other than a
controlling financial interest, and how to determine when and which business
enterprise, or the Primary Beneficiary, should consolidate the VIE. This new
model for consolidation applies to an entity in which either (1) the entity
lacks sufficient equity to absorb expected losses without additional
subordinated financial support or (2) its equity holders as a group are not able
to make decisions about the entity's activities. FIN 46 applies immediately to
VIEs created or acquired after January 31, 2003. On October 10, 2003, the FASB
issued FASB Staff Position ("FSP") FIN 46-6, "Effective Date of FASB
Interpretation No. 46, `Consolidation of Variable Interest Entities'" ("FSP FIN
46-6"). FSP FIN 46-6 defers the effective date for the application of FIN 46 to
VIEs created before February 1, 2003, to an entity's first reporting period
ending after December 15, 2003. One possible consequence of FIN 46 is that
certain investments accounted for under the equity method and off balance sheet
entities might have to be consolidated. However, based on our preliminary
assessment, and subject to further analysis, we do not believe that FIN 46 will
require any of our pre-February 1, 2003 equity method investments or off balance
sheet entities to be consolidated.
Acadia Powers Partners, LLC ("Acadia") is the owner of a 1,160-megawatt
electric wholesale generation facility located in Louisiana and is a joint
venture between Calpine and Cleco Corporation. The joint venture was formed in
July 2001, but due to a change in the partnership agreement in May 2003, we were
required to reconsider our investment in the entity under the FIN 46 guidance.
We determined that Acadia was a VIE and that we held a significant variable
interest (50%) in the entity. However, we were not the primary beneficiary and
therefore not required to consolidate the entity's assets and liabilities. The
net equity in Acadia was approximately $502 million as of September 30, 2003. We
continue to account for this investment under the equity method. Our maximum
potential exposure to loss at September 30,2003, as a result of its involvement
in the joint venture, was approximately $229.2 million.
In April 2003 the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial reporting for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities
under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract
with an initial net investment meets the characteristic of a derivative,
clarifies when a derivative contains a financing component, amends the
definition of an underlying to conform it to language used in FIN 45, and amends
certain other existing pronouncements. SFAS No. 149 is effective for contracts
entered into or modified after June 30, 2003, and should be applied
prospectively, with the exception of certain SFAS No. 133 implementation issues
that were effective for all fiscal quarters prior to June 15, 2003. Any such
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implementation issues should continue to be applied in accordance with their
respective effective dates. The adoption of SFAS No. 149 did not have a material
impact on our financial statements.
In May 2003 the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. SFAS
No. 150 applies specifically to a number of financial instruments that companies
have historically presented within their financial statements either as equity
or between the liabilities section and the equity section, rather than as
liabilities. SFAS No. 150 was effective for financial instruments entered into
or modified after May 31, 2003, and otherwise was effective at the beginning of
the first interim period beginning after June 15, 2003.
We adopted SFAS No. 150 on July 1, 2003. As a result, approximately $82
million of mandatorily redeemable noncontrolling interest (not related to
finite-lived subsidiaries) in our King City facility, which had previously been
included within the balance sheet caption "Minority interests", was reclassified
to "Notes payable". Preferential distributions related to this mandatorily
redeemable noncontrolling interest are to be made annually beginning November
2003 through November 2019 and total approximately $169 million over the 17-year
period. The preferred interest holders' recourse is limited to the net assets of
the entity and the distribution terms defined in the agreement. We have not
guaranteed the payment of these preferential distributions. The distributions
and accretion of issuance costs related to this preferred interest, which was
previously reported as a component of "Minority interest expense" in the
Consolidated Condensed Statements of Operations, is now accounted for as
interest expense. Distributions and related accretion associated with this
preferred interest was $2.7 million for the three months ended September 30,
2003. SFAS No. 150 does not permit reclassification of prior period amounts to
conform to the current period presentation.
During the third quarter of 2003, we completed sales of preferred equity
interests in Auburndale Holdings, LLC and Gilroy Energy Center, LLC. These
interests, in addition to the King City interest, are classified as debt on our
condensed consolidated balance sheet as of September 30, 2003. Although we
cannot readily determine the potential cost to repurchase the interests, the
aggregate carrying value of our partners' interests is approximately $244
million.
In November 2003 the FASB indefinitely deferred certain provisions of SFAS
No. 150 as they apply to mandatorily redeemable noncontrolling (minority)
interests associated with finite-lived subsidiaries. Upon the FASB's
finalization of this issue, we may be required to reclassify approximately $310
million of minority interest relating to our Canadian Calpine Power Income Fund
("Fund") as of September 30, 2003. We own approximately 30% of the Fund, which
is finite-lived and terminates on December 31, 2050. The Fund is consolidated
due to our exercise of substantial control over the Fund's assets and
operations.
The adoption of SFAS No. 150 and related balance sheet reclassifications
did not have an effect on net income or total stockholders equity but have
impacted our debt-to-equity and debt-to-capitalization ratios.
In June 2003, the FASB issued Derivatives Implementation Group ("DIG")
Issue No. C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly
and Closely Related in Paragraph 10(b) regarding Contracts with a Price
Adjustment Feature." DIG Issue No. C20 superseded DIG Issue No. C11
"Interpretation of Clearly and Closely Related in Contracts That Qualify for the
Normal Purchases an Normal Sales Exception" and specified additional
circumstances in which a price adjustment feature in a derivative contract would
not be an impediment to qualifying for the normal purchases and normal sales
scope exception under SFAS No. 133. DIG Issue No. C20 is effective as of the
first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1,
2003, for Calpine) with early application permitted. It should be applied
prospectively for all existing contracts as of the effective date and for all
future transactions. In conjunction with initially applying the implementation
guidance, DIG Issue No. C20 requires the recognition of a special transition
adjustment for certain contracts containing a price adjustment feature based on
a broad market index for which the normal purchases and normal sales scope
exception had been previously elected. In those circumstances, the derivative
contract should be recognized at fair value as of the date of the initial
application with a corresponding adjustment of net income as the cumulative
effect of a change in accounting principle. It should then be applied
prospectively for all existing contracts as of the effective date and for all
future transactions.
Certain of our power sales contracts, which meet the definition of a
derivative and for which we previously elected the normal purchases and normal
sales scope exception, use a CPI or similar index to escalate the Operations and
Maintenance ("O&M") charges. Accordingly, DIG Issue No. C20 has required us to
record a special transition accounting adjustment upon adoption of the new
guidance to record these contracts at fair value with a corresponding adjustment
to net income as the effect of a change in accounting principle. The fair value
of these contracts is based in large part on the nature and extent of the key
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price adjustment features of the contracts and market conditions on date of
adoption, such as the forward price of power and natural gas and the expected
future rate of inflation. On October 1, 2003, we adopted DIG Issue No. C20 and
recorded other current assets and other assets of approximately $33.5 million
and $260 million, respectively, and a cumulative effect adjustment to net income
of approximately $182 million, net of $111 million of tax. The recorded balance
for these contracts will reverse through charges to income over the life of the
long term contracts, which extend out as far as the year 2023, as deliveries of
power are made.
We are currently evaluating the potential impact of EITF Issue No. 03-11,
"Reporting Realized Gains and Losses on Derivative Instruments That Are Subject
to FASB Statement No. 133 and Not `Held for Trading Purposes' As Defined in EITF
Issue No. 02-3: `Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities."' In EITF Issue No. 02-3 the Task Force reached a consensus that
companies should present all gains and losses on derivative instruments held for
trading purposes net in the income statement, whether or not settled physically.
EITF Issue No. 03-11 addresses income statement classification of derivative
instruments held for other than trading purposes. At the July 31, 2003, EITF
meeting, the Task Force reached a consensus that determining whether realized
gains and losses on derivative contracts not "held for trading purposes" should
be reported on a net or gross basis is a matter of judgment that depends on the
relevant facts and circumstances. The Task Force ratified this consensus at its
August 13, 2003, meeting, and it is effective beginning October 1, 2003. The
Task Force did not prescribe special effective date or transition guidance for
this Issue. Application of EITF 03-11 may require or allow us to net revenues
and expenses associated with hedging, balancing and optimization ("HBO")
activities, which could result in a substantial reduction in revenues and cost
of revenues in future periods but would not impact gross profit or net income.
For the three and nine months ended September 30, 2003, our HBO revenues were
$1.1 billion or 43% of our total revenue and $3.2 billion or 46% of our total
revenue, respectively. Overall, we believe netting our HBO activity would
provide a superior presentation of our true level of activity and growth
patterns compared to the existing gross presentation, so we will be carefully
evaluating this new accounting guidance.
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 as of the end of the period covered
by 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 information we are
required to disclose in reports that we file or submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in Securities and Exchange Commission rules and forms.
There was no change in our internal control over financial reporting that
occurred during the period covered by this Quarterly Report on Form 10-Q that
has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting. The certificates required by this
item are filed as a Exhibit 31 to this Form 10-Q.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
The Company is party to various litigation matters arising out of the
normal course of business, the more significant of which are summarized below.
The ultimate outcome of each of these matters cannot presently be determined,
nor can the liability that could potentially result from a negative outcome be
reasonably estimated presently for every case. The liability the Company may
ultimately incur with respect to any one of these matters in the event of a
negative outcome may be in excess of amounts currently accrued with respect to
such matters and, as a result, these matters may potentially be material to the
Company's Consolidated Condensed Financial Statements.
Securities Class Action Lawsuits. Since March 11, 2002, fourteen
shareholder lawsuits have been filed against the Company and certain of its
officers in the United States District Court, Northern District of California.
The actions captioned Weisz vs. 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 vs. Calpine Corp., Lukowski vs.
Calpine Corp., Hart vs. Calpine Corp., Atchison vs. Calpine Corp., Laborers
Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp.
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Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp, and
Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The
complaints in these eleven actions are virtually identical - they are filed by
three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of 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 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.
In addition, a fifteenth securities class action, Ser v. Calpine, et al.,
was filed on May 13, 2002. The underlying allegations in the Ser action are
substantially the same as those in the above-referenced actions. However, the
Ser action is brought on behalf of a purported class of purchasers of Calpine's
8.5% Senior Notes due February 15, 2011 ("2011 Notes") and the alleged class
period is October 15, 2001 through December 13, 2001. The Ser complaint alleges
that, in violation of Sections 11 and 15 of the Securities Act of 1933, the
Supplemental Prospectus for the 2011 Notes contained false and misleading
statements regarding the Company's financial condition. This action names the
Company, certain of its officers and directors, and the underwriters of the 2011
Notes offering as defendants, and seeks an unspecified amount of damages, in
addition to other forms of relief.
All fifteen of these securities class action lawsuits were consolidated in
the U.S. District Court for the Northern District Court of California. The
plaintiffs filed a first amended complaint in October 2002. The amended
complaint did not include the 1933 Act complaints raised in the bondholders'
complaint, and the number of defendants named was reduced. On January 16, 2003,
before our response was due to this amended complaint, the plaintiffs filed a
second amended complaint. This second amended complaint added three additional
Calpine executives and Arthur Andersen LLP as defendants. The second amended
complaint set forth additional alleged violations of Section 10 of the
Securities Exchange Act of 1934 relating to allegedly false and misleading
statements made regarding Calpine's role in the California energy crisis, the
long term power contracts with the California Department of Water Resources, and
Calpine's dealings with Enron, and additional claims under Section 11 and
Section 15 of the Securities Act of 1933 relating to statements regarding the
causes of the California energy crisis. We filed a motion to dismiss this
consolidated action in early April 2003.
On August 29, 2003, the judge issued an order dismissing, with leave to
amend, all of the allegations set forth in the second amended complaint except
for a claim under Section 11 of the Securities Act relating to statements
relating to the causes of the California energy crisis and the related increase
in wholesale prices contained in the Supplemental Prospectuses for the 2011
Notes. The judge instructed plaintiffs to file a third amended complaint, which
they did on October 20, 2003. The third amended complaint names Calpine and
three executives as defendants and alleges the Section 11 claim that survived
the judges August 29, 2003 order. We consider the lawsuit to be without merit
and we intend to defend vigorously against these allegations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities
class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al., was
filed on March 11, 2003, against Calpine, its directors and certain investment
banks in the California Superior Court, San Diego County. The underlying
allegations in the Hawaii Structural Ironworkers Pension Fund action ("Hawaii
action") are substantially the same as the federal securities class actions
described above. However, the Hawaii action is brought on behalf of a purported
class of purchasers of the Company's equity securities sold to public investors
in its April 2002 equity offering. The Hawaii action alleges that the
Registration Statement and Prospectus filed by Calpine which became effective on
April 24, 2002, contained false and misleading statements regarding the
Company's financial condition in violation of Sections 11, 12 and 15 of the
Securities Act of 1933. The Hawaii action relies in part on the Company's
restatement of certain past financial results, announced on March 3, 2003, to
support its allegations. The Hawaii action seeks an unspecified amount of
damages, in addition to other forms of relief. The Company removed the Hawaii
action to federal court in April 2003 and filed a motion to transfer the case
for consolidation with the other securities class action lawsuits in the U.S.
District Court for the Northern District Court of California in May 2003. The
plaintiff has sought to have the action remanded to state court. On August 27,
2003, the U.S. District Court for the Southern District of California granted
plaintiff's motion to remand the action to state court. In early October 2003
plaintiff agreed to dismiss the claims it has against three of the outside
directors. On November 5, 2003, Calpine filed a motion to dismiss this complain.
The Company considers this lawsuit to be without merit and intends to defend
vigorously against it.
Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in
the Calpine Corporation Retirement Savings Plan (the "401(k) Plan") filed a
class action lawsuit in the Northern District Court of California. The
underlying allegations in this action ("Phelps action") are substantially the
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same as those in the securities class actions described above. However, the
Phelps action is brought on behalf of a purported class of participants in the
401(k) Plan. The Phelps action alleges that various filings and statements made
by Calpine during the class period were materially false and misleading, and
that the defendants failed to fulfill their fiduciary obligations as fiduciaries
of the 401(k) Plan by allowing the 401(k) Plan to invest in Calpine common
stock. The Phelps action seeks an unspecified amount of damages, in addition to
other forms of Shareholder relief. In May 2003 Lennette Poor-Herena, another
participant in the 401(k) Plan, filed a substantially similar class action
lawsuit as the Phelps action also in the Northern District of California.
Plaintiffs' counsel is the same in both of these actions, and they have agreed
to consolidate these two cases and to coordinate them with the consolidated
federal securities class actions described above. The Company considers these
lawsuits to be without merit and intends to vigorously defend against them.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of the Company against its directors and
one if its senior officers. This lawsuit is captioned Johnson v. Cartwright, et
al. 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 Calpine and stock sales by certain of
the director defendants and the officer defendant. In December 2002 the court
dismissed the complaint with respect to certain of the director defendants for
lack of personal jurisdiction, though the plaintiff may appeal this ruling. In
early February 2003 the plaintiff filed an amended complaint. In March 2003 the
Company and the individual defendants filed motions to dismiss and motions to
stay this proceeding in favor of the federal securities class actions described
above. In July 2003 the Court granted the motions to stay this proceeding in
favor of the federal securities class actions. The Company considers this
lawsuit to be without merit and intends to vigorously defend against it.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District
California on behalf of Calpine against its directors, captioned Gordon v.
Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003 plaintiff agreed to stay these proceedings in
favor of the consolidated federal securities class actions described above and
to dismiss without prejudice certain director defendants. On March 4, 2003, the
plaintiff filed papers with the court voluntarily agreeing to dismiss without
prejudice the claims he had against three of the outside directors. We consider
this lawsuit to be without merit and intend to continue to defend vigorously
against it.
Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, 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"). Calpine wrote off $17.7 million in December 2001 related
to losses that it alleged were caused by ACE. Calpine and ACE entered into a
settlement agreement on March 29, 2002, pursuant to which ACE made a payment to
the Company of $7 million and transferred to the Company the rights to the
emission reduction credits to be held by ACE. The Company recognized the $7
million as income in the second quarter of 2002. In June 2002 a complaint was
filed by InterGen North America, L.P. ("InterGen") against Anne M. Sholtz, the
owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for
bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of
emission reduction credits from EonXchange in a manner similar to 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. Ann Sholtz
recently stipulated to agree to the consolidation of Anne Sholtz, ACE and other
Sholtz entities in the EonXchange bankruptcy proceeding. On July 10, 2003,
Howard Grobstein, the Trustee in the EonXchange bankruptcy, filed a complaint
for avoidance against Calpine, seeking recovery of the $7 million (plus interest
and costs) paid to Calpine in the March 29, 2002 Settlement Agreement. The
complaint claims that the $7 million received by Calpine in the Settlement
Agreement was transferred within 90 days of the filing of bankruptcy and
therefore should be avoided and preserved for the benefit of the bankruptcy
estate. On August 28, 2003, Calpine filed its answer denying that the $7 million
is an avoidable preference. Discovery is currently ongoing. Calpine believes
that it has valid defenses to this claim and will vigorously defend against this
complaint.
International Paper Company v. Androscoggin Energy LLC. In October 2000
International Paper Company ("IP") filed a complaint in the Federal District
Court for the Northern District of Illinois against Androscoggin Energy LLC
("AELLC") alleging that AELLC breached certain contractual representations and
warranties by failing to disclose facts surrounding the termination, effective
May 8, 1998, of one of AELLC's fixed-cost gas supply agreements. The Company had
acquired a 32.3% interest in AELLC as part of the SkyGen transaction which
closed in October 2000. AELLC filed a counterclaim against IP that has been
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referred to arbitration. AELLC may commence the arbitration counterclaim after
discovery has progressed further. On November 7, 2002, the Court issued an
opinion on the parties' cross motions for summary judgment finding in AELLC's
favor on certain matters though granting summary judgment to IP on the liability
aspect of a particular claim against AELLC. The Court also denied a motion
submitted by IP for preliminary injunction to permit IP to make payment of funds
into escrow (not directly to AELLC) and require AELLC to post a significant
bond. The Court has a set schedule for disclosure of expert witness and
depositions thereof and has tentatively scheduled the case for trial in the
first quarter of 2004.
In mid-April of 2003 IP unilaterally availed itself to self-help in
withholding amounts in excess of $2.0 million as a set-off for litigation
expenses and fees incurred to date as well as an estimated portion of a rate
fund to AELLC. AELLC has submitted an amended complaint and request for
immediate injunctive relief against such actions. The Court heard the motion on
April 24, 2003, and ordered that IP must pay the approximately $1.2 million
withheld as attorneys' fees related to the litigation as any such perceived
entitlement was premature, but deferred to provide injunctive relief on the
incomplete record concerning the offset of $799,000 as an estimated pass-through
of the rate fund. IP complied with the order on April 29, 2003, and tendered
payment to AELLC of the approximately $1.2 million. On June 26, 2003, the court
entered an order dismissing AELLC's Amended Counterclaim without prejudice to
AELLC refiling the claims as breach of contract claims in separate lawsuit. On
June 30, 2003, AELLC filed a motion to reconsider the order dismissing AELLC's
Amended Counterclaim. On October 7, 2003, IP filed a Motion for Summary Judgment
on certain damages issues. AELLC as well anticipates filing a Motion for Summary
Judgment on certain damages issues forthwith. The case is tentatively scheduled
for trial in the first quarter of 2004. The Company believes it has adequately
reserved for the possible loss, if any, it may ultimately incur as a result of
this matter.
Pacific Gas and Electric Company v. Calpine Corporation, et. al. On July
22, 2003, Pacific Gas and Electric Company ("PG&E") filed with the California
Public Utilities Commission ("CPUC") a Complaint of PG&E and Request for
Immediate Issuance of an Order to Show Cause ("Complaint") against Calpine
Corporation, CPN Pipeline Company, Calpine Energy Services, L.P., Calpine
Natural Gas Company, and Lodi Gas Storage, LLC ("LGS"). The complaint requests
the CPUC to issue an order requiring the defendants to show cause why they
should not be ordered to cease and desist from using any direct interconnections
between the facilities of CPN Pipeline and those of LGS unless LGS and Calpine
first seek and obtain regulatory approval from the CPUC. The Complaint also
seeks an order directing defendants to pay to PG&E any underpayments of PG&E's
tariffed transportation rates and to make restitution for any profits earned
from any business activity related to LGS' direct interconnections to any entity
other than PG&E. The Complaint also alleges that various natural gas consumers,
including Company-affiliated generation projects within California, are engaged
with defendants in the acts complained of, and that the defendants unlawfully
bypass PG&E's system and operate as an unregulated local distribution company
within PG&E's service territory. On August 27, 2003, Calpine filed its answer
and a motion to dismiss. LGS has also made similar filings, and Calpine is
contractually obligated to indemnify LGS for certain losses it may suffer as a
result of the Complaint. Calpine has denied the allegations in the Complaint,
believes this Complaint to be without merit and intends to vigorously defend its
position at the CPUC. On October 16, 2003, the presiding administrative law
judge denied the motion to dismiss and on October 24, 2003, issued a Scoping
Memo and Ruling establishing a procedural schedule and setting the evidentiary
hearing to commence on February 17, 2004. Discovery is currently ongoing.
Panda Energy International, Inc. v. Calpine Corporation, et al. On November
5, 2003, Panda Energy International, Inc. and certain related parties
(collectively "Panda") filed suit against the Company and certain of its
affiliates alleging, among other things, that the Company breached duties of
care and loyalty allegedly owed to Panda by failing to construct and operate the
Oneta power plant, which the Company acquired from Panda, in accordance with
Panda's original plans. Panda claims to be entitled to a portion of the profits
of the Oneta plant and that the Company's alleged failures have reduced the
profits from the Oneta plant thereby undermining Panda's ability to repay monies
owed to the Company due on December 1, 2003. The Company and Panda have begun
discussions regarding this matter. We consider the lawsuit to be without merit
and intend to defend vigorously against it.
Item 6. Exhibits and Reports on Form 8-K.
(a)Exhibits
The following exhibits are filed herewith unless otherwise indicated:
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EXHIBIT INDEX
Exhibit
Number Description
------ --------------------------------------------------------------------
*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation (a)
*3.2 Certificate of Correction of Calpine Corporation (b)
*3.3 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of Calpine Corporation (c)
*3.4 Certificate of Designation of Series A Participating Preferred Stock
of Calpine Corporation (b)
*3.5 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (b)
*3.6 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (c)
*3.7 Certificate of Designation of Special Voting Preferred Stock of
Calpine Corporation (d)
*3.8 Certificate of Ownership and Merger Merging Calpine Natural Gas GP,
Inc. into Calpine Corporation (e)
*3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas
Company into Calpine Corporation (e)
*3.10 Amended and Restated By-laws of Calpine Corporation (f)
*4.1 Indenture dated as of July 16, 2003, between Calpine Corporation and
Wilmington Trust Company, as Trustee, including form of Notes (g)
*4.2 Indenture dated as of July 16, 2003, between Calpine Corporation and
Wilmington Trust Company, as Trustee, including form of Notes (g)
*4.3 Indenture dated as of July 16, 2003, between Calpine Corporation and
Wilmington Trust Company, as Trustee, including form of Notes (g)
+4.4 Indenture dated as of August 14, 2003, among Calpine Construction
Finance Company, L.P., CCFC Finance Corp., and each of Calpine
Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership,
as Guarantors, and Wilmington Trust FSB, as Trustee, including form
of Notes
+4.5 Supplemental Indenture dated as of September 18, 2003, Calpine
Construction Finance Company, L.P., CCFC Finance Corp., and each of
Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee
+4.6 Indenture dated as of September 30, 2003, among Gilroy Energy
Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy
Center, LLC, as Guarantors, and Wilmington Trust Company, as Trustee
and Collateral Agent, including form of Notes
*10.1 Amended and Restated Credit Agreement dated as of July 16, 2003
("Amended and Restated Credit Agreement"), among Calpine
Corporation, the Lenders named therein, The Bank of Nova Scotia, as
Administrative Agent, Funding Agent, Lead Arranger and Bookrunner,
Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger,
Co-Bookrunner and Documentation Agent and ING Capital LLC and
Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and
Co-Syndication Agents (g)
*10.2 First Amendment to Amended and Restated Credit Agreement dated as of
August 7, 2003, among Calpine Corporation, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent (g)
+10.3 Amendment and Waiver Request with respect to Amended and Restated
Credit Agreement dated as of August 28, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent and Funding Agent
+10.4 Letter Agreement regarding Second Amendment to Amended and Restated
Credit Agreement dated as of September 5, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent and Funding Agent
+10.5 Third Amendment to Amended and Restated Credit Agreement dated as of
November 6, 2003, among Calpine Corporation, Quintana Minerals
(USA), Inc., as a guarantor, JOQ Canada, Inc., as a guarantor,
Quintana Canada Holdings, LLC, as a guarantor, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent
*10.6 Credit Agreement dated as of July 16, 2003, among Calpine
Corporation, the Lenders named therein, Goldman Sachs Credit
Partners L.P., as Sole Lead Arranger, Sole Bookrunner and
Administrative Agent, The Bank of Nova Scotia, as Arranger and
Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC
and Landesbank Hessen-Thuringen, as Co-Arrangers and Credit Lyonnais
New York Branch and Union Bank of California, N.A., as Managing
Agents (g)
*10.7 Letter of Credit Agreement dated as of July 16, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent (g)
*10.8 Guarantee and Collateral Agreement dated as of July 16, 2003, made
by Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA)
Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New
York, as Collateral Trustee (g)
-78-
Exhibit
Number Description
------ --------------------------------------------------------------------
*10.9 First Amendment Pledge Agreement dated as of July 16, 2003, made by
JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada
Holdings LLC in favor of The Bank of New York, as Collateral Trustee
(g)
*10.10 First Amendment Assignment and Security Agreement dated as of July
16, 2003, made by Calpine Corporation in favor of The Bank of New
York, as Collateral Trustee (g)
*10.11 Second Amendment Pledge Agreement (Stock Interests) dated as of July
16, 2003, made by Calpine Corporation in favor of The Bank of New
York, as Collateral Trustee (g)
*10.12 Second Amendment Pledge Agreement (Membership Interests) dated as of
July 16, 2003, made by Calpine Corporation in favor of The Bank of
New York, as Collateral Trustee (g)
*10.13 First Amendment Note Pledge Agreement dated as of July 16, 2003,
made by Calpine Corporation in favor of The Bank of New York, as
Collateral Trustee (g)
*10.14 Collateral Trust Agreement dated as of July 16, 2003, among Calpine
Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc.,
Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee,
The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners
L.P., as Administrative Agent, and The Bank of New York, as
Collateral Trustee (g)
*10.15 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing
(Multistate) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Denis O'Meara and James Trimble, as Trustees, and The Bank
of New York, as Collateral Trustee (g)
*10.16 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing
(Multistate) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of
New York, as Collateral Trustee (g)
*10.17 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing
(Colorado) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of
New York, as Collateral Trustee (g)
*10.18 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing (New
Mexico) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of
New York, as Collateral Trustee (g)
*10.19 Form of Amended and Restated Mortgage, Assignment, Security
Agreement and Financing Statement (Louisiana) dated as of July 16,
2003, from Calpine Corporation to The Bank of New York, as
Collateral Trustee (g)
*10.20 Form of Amended and Restated Deed of Trust with Power of Sale,
Assignment of Production, Security Agreement, Financing Statement
and Fixture Filings (California) dated as of July 16, 2003, from
Calpine Corporation to Chicago Title Insurance Company, as Trustee,
and The Bank of New York, as Collateral Trustee (g)
*10.21 Form of Deed to Secure Debt, Assignment of Rents and Security
Agreement (Georgia) dated as of July 16, 2003, from Calpine
Corporation to The Bank of New York, as Collateral Trustee (g)
*10.22 Form of Mortgage, Assignment of Rents and Security Agreement
(Florida) dated as of July 16, 2003, from Calpine Corporation to The
Bank of New York, as Collateral Trustee (g)
*10.23 Form of Deed of Trust, Assignment of Rents and Security Agreement
and Fixture Filing (Texas) dated as of July 16, 2003, from Calpine
Corporation to Malcolm S. Morris, as Trustee, in favor of The Bank
of New York, as Collateral Trustee (g)
*10.24 Form of Deed of Trust, Assignment of Rents and Security Agreement
(Washington) dated as of July 16, 2003, from Calpine Corporation to
Chicago Title Insurance Company, in favor of The Bank of New York,
as Collateral Trustee (g)
*10.25 Form of Deed of Trust, Assignment of Rents, and Security Agreement
(California) dated as of July 16, 2003, from Calpine Corporation to
Chicago Title Insurance Company, in favor of The Bank of New York,
as Collateral Trustee (g)
*10.26 Form of Mortgage, Collateral Assignment of Leases and Rents,
Security Agreement and Financing Statement (Louisiana) dated as of
July 16, 2003, from Calpine Corporation to The Bank of New York, as
Collateral Trustee (g)
*10.27 Amended and Restated Hazardous Materials Undertaking and Indemnity
(Multistate) dated as of July 16, 2003, by Calpine Corporation in
favor of The Bank of New York, as Collateral Trustee (g)
*10.28 Amended and Restated Hazardous Materials Undertaking and Indemnity
(California) dated as of July 16, 2003, by Calpine Corporation in
favor of The Bank of New York, as Collateral Trustee (g)
-79-
Exhibit
Number Description
------ --------------------------------------------------------------------
+10.29 Credit and Guarantee Agreement dated as of August 14, 2003, among
Calpine Construction Finance Company, L.P., each of Calpine
Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership,
as Guarantors, the Lenders from time to time party thereto, and
Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole
Lead Arranger
+10.30 Amendment No. 1 to the Credit and Guarantee Agreement dated as of
September 12, 2003, among Calpine Construction Finance Company,
L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and
Hermiston Power Partnership, as Guarantors, the Lenders from time to
time party thereto, and Goldman Sachs Credit Partners L.P., as
Administrative Agent and Sole Lead Arranger
+31.1 Certification of the Chairman, President and Chief Executive Officer
Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
+31.2 Certification of the Executive Vice President and Chief Financial
Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934, as Adopted Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
+32.1 Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002
- ------------
* Incorporated by reference.
+ Filed herewith.
(a) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30,
2000.
(b) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2000, filed with the SEC on March 15,
2001.
(c) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27,
2001.
(d) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.
(e) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.
(f) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2001, filed with the SEC on March 29,
2002.
(g) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
(b)Reports on Form 8-K
The registrant filed or furnished the following reports on Form 8-K during
the quarter ended September 30, 2003:
-80-
Date Filed
Date of Report or Furnished Item Reported
----------------- -------------- ---------------
7/10/03 7/11/03 5
7/16/03 7/16/03 5
7/16/03 7/16/03 5
7/16/03 7/17/03 5
7/16/03 7/23/03 5
7/24/03 7/24/03 5
8/1/03 8/1/03 5
8/6/03 8/7/03 12
8/14/03 8/15/03 5
8/25/03 8/26/03 5
8/27/03 8/28/03 5
9/3/03 9/4/03 5
9/25/03 9/26/03 5
9/25/03 9/29/03 5
-81-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Calpine Corporation
By: /s/ ROBERT D. KELLY
--------------------------------------
Robert D. Kelly
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: November 13, 2003
By: /s/ CHARLES B. CLARK, JR.
--------------------------------------
Charles B. Clark, Jr.
Senior Vice President and Corporate
Controller (Principal Accounting Officer)
Date: November 13, 2003
-82-
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
Exhibit
Number Description
------ --------------------------------------------------------------------
*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation (a)
*3.2 Certificate of Correction of Calpine Corporation (b)
*3.3 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of Calpine Corporation (c)
*3.4 Certificate of Designation of Series A Participating Preferred Stock
of Calpine Corporation (b)
*3.5 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (b)
*3.6 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (c)
*3.7 Certificate of Designation of Special Voting Preferred Stock of
Calpine Corporation (d)
*3.8 Certificate of Ownership and Merger Merging Calpine Natural Gas GP,
Inc. into Calpine Corporation (e)
*3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas
Company into Calpine Corporation (e)
*3.10 Amended and Restated By-laws of Calpine Corporation (f)
*4.1 Indenture dated as of July 16, 2003, between Calpine Corporation and
Wilmington Trust Company, as Trustee, including form of Notes (g)
*4.2 Indenture dated as of July 16, 2003, between Calpine Corporation and
Wilmington Trust Company, as Trustee, including form of Notes (g)
*4.3 Indenture dated as of July 16, 2003, between Calpine Corporation and
Wilmington Trust Company, as Trustee, including form of Notes (g)
+4.4 Indenture dated as of August 14, 2003, among Calpine Construction
Finance Company, L.P., CCFC Finance Corp., and each of Calpine
Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership,
as Guarantors, and Wilmington Trust FSB, as Trustee, including form
of Notes
+4.5 Supplemental Indenture dated as of September 18, 2003, Calpine
Construction Finance Company, L.P., CCFC Finance Corp., and each of
Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power
Partnership, as Guarantors, and Wilmington Trust FSB, as Trustee
+4.6 Indenture dated as of September 30, 2003, among Gilroy Energy
Center, LLC, each of Creed Energy Center, LLC and Goose Haven Energy
Center, LLC, as Guarantors, and Wilmington Trust Company, as Trustee
and Collateral Agent, including form of Notes
*10.1 Amended and Restated Credit Agreement dated as of July 16, 2003
("Amended and Restated Credit Agreement"), among Calpine
Corporation, the Lenders named therein, The Bank of Nova Scotia, as
Administrative Agent, Funding Agent, Lead Arranger and Bookrunner,
Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger,
Co-Bookrunner and Documentation Agent and ING Capital LLC and
Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and
Co-Syndication Agents (g)
*10.2 First Amendment to Amended and Restated Credit Agreement dated as of
August 7, 2003, among Calpine Corporation, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent (g)
+10.3 Amendment and Waiver Request with respect to Amended and Restated
Credit Agreement dated as of August 28, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent and Funding Agent
+10.4 Letter Agreement regarding Second Amendment to Amended and Restated
Credit Agreement dated as of September 5, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent and Funding Agent
+10.5 Third Amendment to Amended and Restated Credit Agreement dated as of
November 6, 2003, among Calpine Corporation, Quintana Minerals
(USA), Inc., as a guarantor, JOQ Canada, Inc., as a guarantor,
Quintana Canada Holdings, LLC, as a guarantor, the Lenders named
therein, and The Bank of Nova Scotia, as Administrative Agent and
Funding Agent
*10.6 Credit Agreement dated as of July 16, 2003, among Calpine
Corporation, the Lenders named therein, Goldman Sachs Credit
Partners L.P., as Sole Lead Arranger, Sole Bookrunner and
Administrative Agent, The Bank of Nova Scotia, as Arranger and
Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC
and Landesbank Hessen-Thuringen, as Co-Arrangers and Credit Lyonnais
New York Branch and Union Bank of California, N.A., as Managing
Agents (g)
*10.7 Letter of Credit Agreement dated as of July 16, 2003, among Calpine
Corporation, the Lenders named therein, and The Bank of Nova Scotia,
as Administrative Agent (g)
*10.8 Guarantee and Collateral Agreement dated as of July 16, 2003, made
by Calpine Corporation, JOQ Canada, Inc., Quintana Minerals (USA)
Inc., and Quintana Canada Holdings LLC, in favor of The Bank of New
York, as Collateral Trustee (g)
-83-
Exhibit
Number Description
------ --------------------------------------------------------------------
*10.9 First Amendment Pledge Agreement dated as of July 16, 2003, made by
JOQ Canada, Inc., Quintana Minerals (USA) Inc., and Quintana Canada
Holdings LLC in favor of The Bank of New York, as Collateral Trustee
(g)
*10.10 First Amendment Assignment and Security Agreement dated as of July
16, 2003, made by Calpine Corporation in favor of The Bank of New
York, as Collateral Trustee (g)
*10.11 Second Amendment Pledge Agreement (Stock Interests) dated as of July
16, 2003, made by Calpine Corporation in favor of The Bank of New
York, as Collateral Trustee (g)
*10.12 Second Amendment Pledge Agreement (Membership Interests) dated as of
July 16, 2003, made by Calpine Corporation in favor of The Bank of
New York, as Collateral Trustee (g)
*10.13 First Amendment Note Pledge Agreement dated as of July 16, 2003,
made by Calpine Corporation in favor of The Bank of New York, as
Collateral Trustee (g)
*10.14 Collateral Trust Agreement dated as of July 16, 2003, among Calpine
Corporation, JOQ Canada, Inc., Quintana Minerals (USA) Inc.,
Quintana Canada Holdings LLC, Wilmington Trust Company, as Trustee,
The Bank of Nova Scotia, as Agent, Goldman Sachs Credit Partners
L.P., as Administrative Agent, and The Bank of New York, as
Collateral Trustee (g)
*10.15 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing
(Multistate) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Denis O'Meara and James Trimble, as Trustees, and The Bank
of New York, as Collateral Trustee (g)
*10.16 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing
(Multistate) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of
New York, as Collateral Trustee (g)
*10.17 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing
(Colorado) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of
New York, as Collateral Trustee (g)
*10.18 Form of Amended and Restated Mortgage, Deed of Trust, Assignment,
Security Agreement, Financing Statement and Fixture Filing (New
Mexico) dated as of July 16, 2003, from Calpine Corporation to
Messrs. Kemp Leonard and John Quick, as Trustees, and The Bank of
New York, as Collateral Trustee (g)
*10.19 Form of Amended and Restated Mortgage, Assignment, Security
Agreement and Financing Statement (Louisiana) dated as of July 16,
2003, from Calpine Corporation to The Bank of New York, as
Collateral Trustee (g)
*10.20 Form of Amended and Restated Deed of Trust with Power of Sale,
Assignment of Production, Security Agreement, Financing Statement
and Fixture Filings (California) dated as of July 16, 2003, from
Calpine Corporation to Chicago Title Insurance Company, as Trustee,
and The Bank of New York, as Collateral Trustee (g)
*10.21 Form of Deed to Secure Debt, Assignment of Rents and Security
Agreement (Georgia) dated as of July 16, 2003, from Calpine
Corporation to The Bank of New York, as Collateral Trustee (g)
*10.22 Form of Mortgage, Assignment of Rents and Security Agreement
(Florida) dated as of July 16, 2003, from Calpine Corporation to The
Bank of New York, as Collateral Trustee (g)
*10.23 Form of Deed of Trust, Assignment of Rents and Security Agreement
and Fixture Filing (Texas) dated as of July 16, 2003, from Calpine
Corporation to Malcolm S. Morris, as Trustee, in favor of The Bank
of New York, as Collateral Trustee (g)
*10.24 Form of Deed of Trust, Assignment of Rents and Security Agreement
(Washington) dated as of July 16, 2003, from Calpine Corporation to
Chicago Title Insurance Company, in favor of The Bank of New York,
as Collateral Trustee (g)
*10.25 Form of Deed of Trust, Assignment of Rents, and Security Agreement
(California) dated as of July 16, 2003, from Calpine Corporation to
Chicago Title Insurance Company, in favor of The Bank of New York,
as Collateral Trustee (g)
*10.26 Form of Mortgage, Collateral Assignment of Leases and Rents,
Security Agreement and Financing Statement (Louisiana) dated as of
July 16, 2003, from Calpine Corporation to The Bank of New York, as
Collateral Trustee (g)
*10.27 Amended and Restated Hazardous Materials Undertaking and Indemnity
(Multistate) dated as of July 16, 2003, by Calpine Corporation in
favor of The Bank of New York, as Collateral Trustee (g)
*10.28 Amended and Restated Hazardous Materials Undertaking and Indemnity
(California) dated as of July 16, 2003, by Calpine Corporation in
favor of The Bank of New York, as Collateral Trustee (g)
-84-
Exhibit
Number Description
------ --------------------------------------------------------------------
+10.29 Credit and Guarantee Agreement dated as of August 14, 2003, among
Calpine Construction Finance Company, L.P., each of Calpine
Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership,
as Guarantors, the Lenders from time to time party thereto, and
Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole
Lead Arranger
+10.30 Amendment No. 1 to the Credit and Guarantee Agreement dated as of
September 12, 2003, among Calpine Construction Finance Company,
L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and
Hermiston Power Partnership, as Guarantors, the Lenders from time to
time party thereto, and Goldman Sachs Credit Partners L.P., as
Administrative Agent and Sole Lead Arranger
+31.1 Certification of the Chairman, President and Chief Executive Officer
Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
+31.2 Certification of the Executive Vice President and Chief Financial
Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the
Securities Exchange Act of 1934, as Adopted Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002
+32.1 Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section
906 of the Sarbanes-Oxley Act of 2002
- ------------
* Incorporated by reference.
+ Filed herewith.
(a) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30,
2000.
(b) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2000, filed with the SEC on March 15,
2001.
(c) Incorporated by reference to Calpine Corporation's Registration Statement
on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27,
2001.
(d) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.
(e) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.
(f) Incorporated by reference to Calpine Corporation's Annual Report on Form
10-K for the year ended December 31, 2001, filed with the SEC on March 29,
2002.
(g) Incorporated by reference to Calpine Corporation's Quarterly Report on Form
10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.
-85-