UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the quarterly period ended September 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the transition period
from ________ to _________
Commission file number: 1-12079
CALPINE CORPORATION
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
305,317,613 shares of Common Stock, par value $.001 per share, outstanding on
November 12, 2001
CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q/A
For the Quarter Ended September 30, 2001
INDEX
PAGE NO.
PART I - FINANCIAL INFORMATION
INTRODUCTORY NOTE...................................................................................................... 3
ITEM 1. Financial Statements.
Consolidated Condensed Balance Sheets September 30, 2001 and December 31, 2000................... 4
Consolidated Condensed Statements of Operations For the Three and Nine Months
Ended September 30, 2001 and 2000................................................................ 5
Consolidated Condensed Statements of Cash Flows For the Nine Months
Ended September 30, 2001 and 2000................................................................ 6
Notes to Consolidated Condensed Financial Statements September 30, 2001.......................... 7
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............ 24
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk....................................... 39
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings................................................................................ 39
ITEM 2. Changes in Securities and Use of Proceeds........................................................ 39
ITEM 4. Submission of Matters to a Vote of Security Holders.............................................. 39
ITEM 6. Exhibits and Reports on Form 8-K................................................................. 39
Signatures ........................................................................................................... 42
2
INTRODUCTORY NOTE
None of the supplemental information included herein in any way restates the
financial results contained in Calpine Corporation's consolidated condensed
balance sheets, statements of operations or statements of cash flows at, and as
of, September 30, 2001 that were contained in the Quarterly Report on Form 10-Q
for the three and nine months ended September 30, 2001 (as the consolidated
condensed statements of cash flows were amended by Calpine's Current Report on
Form 8-K filed on December 20, 2001), but we have updated and elaborated upon
certain notes thereto. Readers are encouraged to consult the 2000 10-K (as
restated for our merger with Encal Energy Ltd. in our Current Report on Form 8-K
filed on September 10, 2001) and other periodic filings we have made in 2001, as
well as the complete text of this document, for background in understanding the
additional information included herein.
Calpine hereby files this amended version of its Quarterly Report on Form 10-Q/A
for the three and nine month periods ended September 30, 2001. The Quarterly
Report on Form 10-Q for these periods was initially filed with the Securities
and Exchange Commission on November 14, 2001 (the "Original Q3 10-Q"). This
amended version (the "Q3 10-Q/A") is provided to elaborate upon certain
disclosures contained in the Original Q3 10-Q. The accompanying disclosures were
prepared in response to comments received by us from the staff of the division
of Corporation Finance of the Securities and Exchange Commission as part of a
review of our recent periodic filings. The accompanying disclosures are intended
to supplement other periodic filings we have made in 2001.
This Q3 10-Q/A does not update all information contained in the Original Q3
10-Q. Readers are encouraged to consult Calpine's Current Reports on Form 8-K
filed since the Original Q3 10-Q for information relating to events subsequent
to the date of the Original Q3 10-Q.
Calpine will provide a version of this Q3 10-Q/A that is marked to show changes
against the Original Q3 10-Q on the Company website at www.calpine.com under
Investor Relations, Financial Reports and upon request at no charge. Please
direct requests to Calpine Corporation, 50 West San Fernando Street, San Jose,
California, 95113, attention: Lisa M. Bodensteiner, Assistant Secretary;
telephone: (408) 995-5115.
3
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
September 30, 2001 and December 31, 2000
(in thousands, except share and per share amounts)
(unaudited)
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------- ------------
ASSETS
Current assets:
Cash and cash equivalents ................................................................... $ 476,374 $ 596,077
Accounts receivable, net of allowance of $18,825 and $11,555 ................................ 1,054,843 727,893
Inventories ................................................................................. 77,391 44,456
Prepaid expense ............................................................................. 237,457 27,515
Other current assets ........................................................................ 749,974 41,165
------------ ------------
Total current assets ..................................................................... 2,596,039 1,437,106
------------ ------------
Property, plant and equipment, net ............................................................. 13,932,640 7,979,160
Investments in power projects .................................................................. 335,182 205,621
Project development costs ...................................................................... 89,772 38,597
Notes receivable ............................................................................... 443,676 217,927
Restricted cash ................................................................................ 109,193 88,618
Deferred financing costs ....................................................................... 165,974 112,049
Long-term receivable ........................................................................... 271,567 --
Other assets ................................................................................... 865,241 244,125
------------ ------------
Total assets ............................................................................. $ 18,809,284 $ 10,323,203
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and borrowings under lines of credit, current portion ......................... $ 1,120 $ 1,087
Project financing, current portion .......................................................... 1,626 58,486
Capital lease obligation, current portion ................................................... 2,188 1,985
Zero-Coupon Convertible Debentures Due 2021 ................................................. 1,000,000 --
Accounts payable ............................................................................ 1,253,052 843,641
Income taxes payable ........................................................................ 83,821 63,409
Accrued payroll and related expense ......................................................... 55,596 53,667
Accrued interest payable .................................................................... 120,375 77,878
Other current liabilities ................................................................... 951,459 149,080
------------ ------------
Total current liabilities ................................................................ 3,469,237 1,249,233
------------ ------------
Notes payable and borrowings under lines of credit, net of current portion ..................... 206,120 455,067
Project financing, net of current portion ...................................................... 2,620,536 1,473,869
Senior notes ................................................................................... 6,300,040 2,551,750
Capital lease obligation, net of current portion ............................................... 207,149 208,876
Deferred income taxes, net ..................................................................... 1,073,118 618,529
Deferred lease incentive ....................................................................... 58,113 60,676
Deferred revenue ............................................................................... 102,758 92,511
Other liabilities .............................................................................. 677,789 30,529
------------ ------------
Total liabilities ........................................................................ 14,714,860 6,741,040
------------ ------------
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts . 1,122,846 1,122,490
Minority interests ............................................................................. 79,651 37,576
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and
outstanding one share in 2001 and 2000 ................................................... -- --
Common stock, $.001 par value per share; authorized 1,000,000,000 shares in 2001 and
500,000,000 shares in 2000; issued and outstanding 305,159,897
shares in 2001 and 300,074,078 shares in 2000 .................................................. 305 300
Additional paid-in capital .................................................................. 2,018,760 1,896,987
Retained earnings ........................................................................... 1,096,022 547,895
Accumulated other comprehensive loss ........................................................ (223,160) (23,085)
------------ ------------
Total stockholders' equity ............................................................... 2,891,927 2,422,097
------------ ------------
Total liabilities and stockholders' equity ............................................... $ 18,809,284 $ 10,323,203
============ ============
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, 2001 and 2000
(in thousands, except per share amounts)
(unaudited)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
Revenue:
Electric generation and marketing revenue ....................... $ 2,755,603 $ 643,782 $ 5,063,010 $ 1,191,461
Oil and gas production and marketing revenue .................... 139,382 92,851 768,253 229,478
Income from unconsolidated investments in power projects ........ 6,859 7,224 9,022 21,841
Other revenue ................................................... 14,261 957 28,444 4,388
----------- ----------- ----------- -----------
Total revenue ............................................... 2,916,105 744,814 5,868,729 1,447,168
----------- ----------- ----------- -----------
Cost of revenue:
Electric generation and marketing expense ....................... 1,864,069 117,348 3,147,301 248,955
Oil and gas production and marketing expense .................... 71,216 30,090 469,765 85,633
Fuel expense .................................................... 322,100 185,619 807,544 363,315
Depreciation expense ............................................ 91,514 59,125 235,671 154,940
Operating lease expense ......................................... 27,830 25,230 83,290 46,360
Other expense ................................................... 3,485 1,143 9,474 3,923
----------- ----------- ----------- -----------
Total cost of revenue ....................................... 2,380,214 418,555 4,753,045 903,126
----------- ----------- ----------- -----------
Gross profit ................................................ 535,891 326,259 1,115,684 544,042
Project development expense ....................................... 4,894 6,091 25,105 15,074
General and administrative expense ................................ 29,859 28,147 116,481 57,295
Merger expense .................................................... -- -- 41,627 --
----------- ----------- ----------- -----------
Income from operations ...................................... 501,138 292,021 932,471 471,673
Other expense (income):
Interest expense ................................................ 49,695 29,058 112,951 69,013
Distributions on trust preferred securities ..................... 15,385 12,650 45,947 28,713
Interest income ................................................. (21,073) (15,896) (60,962) (29,073)
Other expense (income), net ..................................... (7,875) 1,183 (16,893) 1,439
----------- ----------- ----------- -----------
Income before provision for income taxes .................... 465,006 265,026 851,428 401,581
Provision for income taxes ........................................ 144,207 106,481 303,037 162,427
----------- ----------- ----------- -----------
Income before extraordinary charge and cumulative effect
of a change in accounting principle ....................... 320,799 158,545 548,391 239,154
Extraordinary charge, net of tax benefit .......................... -- (1,235) (1,300) (1,235)
Cumulative effect of a change in accounting principle ............. -- -- 1,036 --
----------- ----------- ----------- -----------
Net income ................................................. $ 320,799 $ 157,310 $ 548,127 $ 237,919
=========== =========== =========== ===========
Basic earnings per common share:
Weighted average shares of common stock outstanding ............ 304,666 285,143 302,649 275,392
Income before extraordinary charge and cumulative effect
of a change in accounting principle .......................... $ 1.05 $ 0.56 $ 1.81 $ 0.87
Extraordinary charge ........................................... $ -- $ (0.01) $ -- $ (0.01)
Cumulative effect of a change in accounting principle .......... $ -- $ -- $ -- $ --
----------- ----------- ----------- -----------
Net income ................................................... $ 1.05 $ 0.55 $ 1.81 $ 0.86
=========== =========== =========== ===========
Diluted earnings per common share:
Weighted average shares of common stock outstanding before
dilutive effect of certain convertible securities ............ 318,552 302,239 317,880 291,705
Income before dilutive effect of certain convertible securities,
extraordinary charge and cumulative effect of a change in
accounting principle ......................................... $ 1.01 $ 0.52 $ 1.73 $ 0.82
Dilutive effect of certain convertible securities (1) .......... $ (0.13) $ (0.03) $ (0.16) $ (0.03)
----------- ----------- ----------- -----------
Income before extraordinary charge and cumulative effect of a
change in accounting principle ............................... $ 0.88 $ 0.49 $ 1.57 $ 0.79
Extraordinary charge ........................................... $ -- $ (0.01) $ -- $ (0.01)
Cumulative effect of a change in accounting principle .......... $ -- $ -- $ -- $ --
----------- ----------- ----------- -----------
Net income ................................................... $ 0.88 $ 0.48 $ 1.57 $ 0.78
=========== =========== =========== ===========
- --------------
(1) Includes the effect of the assumed conversion of certain convertible
securities. For the three and nine months ended September 30, 2001, the
assumed conversion calculation adds 58,153 and 52,353 shares of common
stock and $12,470 and $33,204 to the net income results, representing
the after tax expense on certain convertible securities avoided upon
conversion. For the three and nine months ended September 30, 2000, the
assumed conversion calculation adds 39,573 and 31,338 shares of common
stock and $7,696 and $15,373 to the net income results.
The accompanying notes are an integral part of these consolidated
condensed financial statements.
5
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2001 and 2000
(in thousands)
(unaudited)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2001 2000
------------ ------------
Cash flows from operating activities:
Net income ...................................................................... $ 548,127 $ 237,919
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization ................................................ 242,547 160,373
Deferred income taxes, net ................................................... 202,444 97,355
Income from unconsolidated investments in power projects ..................... (9,022) (21,841)
Distributions from unconsolidated investments in power projects .............. 3,596 26,717
Change in long-term liabilities .............................................. 459,657 (3,465)
Minority interest ............................................................ (3,198) 2,144
Change in operating assets and liabilities, net of effects of
acquisitions:
Accounts receivable .......................................................... (561,964) (227,017)
Inventories .................................................................. (30,025) (7,579)
Other current assets ......................................................... (890,898) (7,151)
Notes receivable ............................................................. (74,709) (36,650)
Other assets ................................................................. (627,076) 9,548
Accounts payable and accrued expense ......................................... 421,451 106,715
Other current liabilities and deferred revenue ............................... 806,786 (1,814)
----------- -----------
Net cash provided by operating activities ................................. 487,716 335,254
----------- -----------
Cash flows from investing activities:
Purchases of property, plant and equipment ...................................... (4,473,444) (1,827,640)
Acquisitions, net of cash acquired .............................................. (1,303,366) (369,036)
Proceeds from sale and leaseback of plant ....................................... -- 400,000
Capital expenditures on joint ventures .......................................... (103,496) (168,234)
Maturities of collateral securities ............................................. 4,035 4,745
Project development costs ....................................................... (55,734) (3,689)
Increase in notes receivable .................................................... (140,152) (78,383)
Decrease (increase) in restricted cash .......................................... (35,740) 11,988
Other ........................................................................... 8,384 (12,505)
----------- -----------
Net cash used in investing activities ..................................... (6,099,513) (2,042,754)
----------- -----------
Cash flows from financing activities:
Proceeds from notes payable and borrowings under lines of credit ................ 141,543 929,637
Repayments of notes payable and borrowings under lines of credit ................ (444,820) (991,989)
Proceeds from project financing ................................................. 2,324,209 463,105
Repayments of project financing ................................................. (1,234,776) (579,047)
Proceeds from issuance of senior notes .......................................... 3,853,290 1,000,000
Repayment of senior notes ....................................................... (105,000) --
Proceeds from issuance of preferred securities .................................. -- 877,500
Proceeds from issuance of convertible securities ................................ 1,000,000 --
Proceeds from issuance of common stock .......................................... 62,283 803,812
Financing costs ................................................................. (84,649) (76,389)
Write-off of deferred financing costs ........................................... -- 2,031
Other ........................................................................... (19,986) 12,365
----------- -----------
Net cash provided by financing activities ................................. 5,492,094 2,441,025
----------- -----------
Net increase (decrease) in cash and cash equivalents ............................... (119,703) 733,525
Cash and cash equivalents, beginning of period ..................................... 596,077 349,371
----------- -----------
Cash and cash equivalents, end of period ........................................... $ 476,374 $ 1,082,896
=========== ===========
Cash paid during the period for:
Interest ........................................................................ $ 381,772 $ 154,668
Income taxes .................................................................... $ 114,667(1) $ 41,035
- --------
(1) Previously amended by the Company's Current Report on Form 8-K filed on
December 20, 2001.
The accompanying notes are an integral part of these consolidated
condensed financial statements.
6
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 30, 2001
(unaudited)
1. Organization and Operation of the Company
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, "the Company") is engaged in the generation of electricity in the
United States, Canada and the United Kingdom. The Company is involved in the
development, acquisition, ownership and operation of power generation facilities
and the sale of electricity and its by-product, thermal energy, primarily in the
form of steam. The Company has ownership interests in and operates gas-fired
power generation and cogeneration facilities, gas fields, gathering systems and
gas pipelines, geothermal steam fields and geothermal power generation
facilities in the United States, Canada and the United Kingdom. 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
cogeneration facilities is primarily sold to governmental and industrial users.
Gas produced and not physically delivered to the Company's generating plants is
sold to third parties.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying unaudited interim consolidated
condensed financial statements of the Company have been prepared by the Company
pursuant to the rules and regulations of the Securities and Exchange Commission.
In the opinion of management, the consolidated condensed financial statements
include the adjustments necessary to present fairly the information required to
be set forth therein. The Company's historical amounts have been restated to
reflect the pooling-of-interests transaction completed during the second quarter
of 2001 for the acquisition of Encal Energy Ltd. ("Encal"). Certain information
and note disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles in the United States
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, 2000 included in the Company's September 10,
2001 Current Report on Form 8-K which gives retroactive effect to the merger
with Encal. The results for interim periods are not necessarily indicative of
the results for the entire year.
Use of Estimates in Preparation of Financial Statements -- The preparation of
financial statements in conformity with generally accepted accounting principles
in the United States 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 future development costs, useful
lives of the generation facilities, and depletion, depreciation and impairment
of natural gas and petroleum property and equipment.
Revenue Recognition -- The Company is primarily an electric generation company,
operating a portfolio of mostly wholly owned plants but also some plants in
which its ownership interest is 50% or less and which are accounted for under
the equity method. In conjunction with its electric generation business, the
Company also produces, as a by-product, thermal energy for sale to customers,
principally steam hosts at its cogeneration sites. In addition, the Company
acquires and produces natural gas for its own consumption and sells the balance
and small amounts of oil to third parties. To protect and enhance the profit
potential of its electric generation plants, the Company, through its
subsidiary, Calpine Energy Services, LP ("CES"), enters into electric and gas
hedging, balancing and related transactions in which purchased electricity and
gas is resold to third parties. CES acts as a principal, takes title to the
commodities purchased for resale, and assumes the risks and rewards of
ownership. Therefore, in accordance with Staff Accounting Bulletin No. 101 and
the Emerging Issues Task Force ("EITF") Issue No. 99-19, CES recognizes revenue
on a gross basis, except in the case of financial swap transactions, in which
case the net gain or loss from the hedging instrument is recorded in income
against the underlying hedged item when the effects of the hedged item are
recognized. Hedged items typically include sales to third parties of natural gas
produced, purchases of natural gas to fuel power plants, and sales of generated
electricity. Finally, the Company, through Power Systems Mfg., LLC ("PSM"),
designs and manufactures spare parts for gas turbines. The Company also
generates small amounts of revenue by occasionally loaning funds to power
projects and by providing operation and maintenance ("O&M") services to
unconsolidated power plants. Further details of the Company's revenue
recognition policy for each type of revenue transaction are provided below:
Electric Generation and Marketing Revenue -- This includes electricity
and steam sales, gains and losses from electric power derivatives and
sales of purchased power. The Company actively manages the revenue
stream for its portfolio of electric
7
generating facilities. CES performs a market-based allocation of
electric generation and marketing revenue to electricity and steam
sales. That allocation is based on electricity delivered by the
Company's electric generating facilities to serve CES contracts. As the
Company actively manages the revenue stream for its portfolio of
electric generation facilities, it is appropriate to review the
Company's financial performance using all electric generation and
marketing revenue.
Oil and Gas Production and Marketing Revenue -- This includes sales to
third parties of gas, oil and related products that are produced by the
Company's Calpine Natural Gas and Calpine Canada Natural Gas
subsidiaries and also sales of purchased gas.
Income from Unconsolidated Investments in Power Projects -- The Company
uses the equity method to recognize as revenue its pro rata share of
the net income or loss of the unconsolidated investment until such
time, if applicable, the Company's investment is reduced to zero, at
which time equity income is generally recognized only upon receipt of
cash distributions from the investee.
Other Revenue -- This includes O&M contract revenue, interest income on
loans to power projects, PSM revenue from sales to third parties and
miscellaneous revenue.
Energy Marketing Operations -- The Company markets energy services to utilities,
wholesalers, and end users. CES provides these services by entering into
contracts to purchase or supply energy, primarily, at specified delivery points
and specified future dates. CES also utilizes financial instruments to manage
its exposure to electricity and natural gas price fluctuations, and to a lesser
degree, price fluctuations of crude oil and refined products. The Company
actively manages its positions. The Company's credit risk associated with energy
contracts results from the risk of loss on non-performance by counterparties.
The Company reviews and assesses counterparty risk to limit any material impact
on its financial position and results of operations. The Company closely
monitors and manages its exposure to all of its counterparties as discussed in
Note 11.
New Accounting Pronouncements -- In June 2001, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 141, "Business Combinations", which supersedes Accounting
Principles Board ("APB") Opinion No. 16, "Business Combinations" and SFAS No.
38, "Accounting for Preacquisition Contingencies of Purchased Enterprises". SFAS
No. 141 eliminates the pooling-of-interests method of accounting for business
combinations and modifies the recognition of intangible assets and disclosure
requirements. The elimination of the pooling-of-interests method is effective
for transactions initiated after June 30, 2001. The remaining provisions of SFAS
No. 141 will be effective for transactions accounted for using the purchase
method that are completed after June 30, 2001. The Company does not believe that
SFAS No. 141 will have a material effect on its consolidated financial
statements.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets", which supersedes APB Opinion No. 17, "Intangible Assets". SFAS No. 142
eliminates the current requirement to amortize goodwill and indefinite-lived
intangible assets, extends the allowable useful lives of certain intangible
assets, and requires impairment testing and recognition for goodwill and
intangible assets. SFAS No. 142 will apply to goodwill and other intangible
assets arising from transactions completed both before and after its effective
date. The provisions of SFAS No. 142 are required to be applied starting with
fiscal years beginning after December 15, 2001. The Company does not believe
that SFAS No. 142 will have a material effect on its consolidated financial
statements. The Company expects to have an unamortized goodwill balance at
December 31, 2001 of $24.4 million, which is being amortized over periods of 10
to 20 years. The annual amortization that will be eliminated is $1.6 million.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations", which amends SFAS No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies". SFAS No. 143 addresses financial accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. SFAS No. 143
requires that the fair value of a liability for an asset retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of
fair value can be made. SFAS No. 143 is effective for financial statements
issued for fiscal years beginning after June 15, 2002. The Company does not
believe that SFAS No. 143 will have a material effect on its consolidated
financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", which supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
and the accounting and reporting provisions of APB Opinion No. 30, "Reporting
the Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions", for the disposal of a segment of a business (as previously
defined in that APB Opinion). SFAS No. 144 establishes a single accounting
model, based on the framework established in SFAS No. 121, for long-lived assets
to be disposed of by sale. SFAS No. 144 also resolves several significant
implementation issues related to SFAS No. 121, such as eliminating the
requirement to allocate goodwill to long-
8
lived assets to be tested for impairment and establishing criteria to define
whether a long-lived asset is held for sale. SFAS No. 144 is effective for
financial statements issued for fiscal years beginning after December 15, 2001.
The Company does not believe that SFAS No. 144 will have a material effect on
its consolidated financial statements.
Reclassifications -- Prior period amounts in the consolidated condensed
financial statements have been reclassified where necessary to conform to the
2001 presentation.
3. Property, Plant and Equipment, Net, and Capitalized Interest
Property, plant and equipment, net, consisted of the following (in thousands):
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------ ------------
Geothermal properties ......................... $ 372,282 $ 334,585
Oil and gas properties ........................ 2,232,865 1,441,175
Buildings, machinery and equipment ............ 5,157,849 1,951,250
Power sales agreements ........................ 143,330 162,086
Gas contracts ................................. 140,221 129,999
Other ......................................... 232,376 145,877
------------ ------------
8,278,923 4,164,972
Less: accumulated depreciation and amortization (868,167) (614,816)
------------ ------------
7,410,756 3,550,156
Land .......................................... 71,964 12,578
Construction in progress ...................... 6,449,920 4,416,426
------------ ------------
Property, plant and equipment, net ............ $ 13,932,640 $ 7,979,160
============ ============
Construction in progress is primarily attributable to gas-fired projects under
construction. Upon commencement of commercial plant operation, these costs are
transferred to buildings, machinery and equipment.
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, as amended by SFAS No. 58. For the nine months
ended September 30, 2001 and 2000, the Company recorded net interest expense of
$113.0 million and $69.0 million, respectively, after capitalizing $246.3
million and $96.7 million, respectively, of interest on general corporate funds
used for construction and after recording $94.9 million and $22.8 million,
respectively, of interest capitalized on funds borrowed for specific
construction projects. Upon commencement of commercial plant operation,
capitalized interest, as a component of the total cost of the plant, is
amortized over the estimated useful life of the plant. The increase in the
amount of interest capitalized during the nine months ended September 30, 2001,
reflects the significant increase in the Company's power plant construction
program.
The Company determines which debt instruments represent a reasonable measure of
the cost of financing construction assets in terms of interest cost incurred
that otherwise could have been avoided. These debt instruments and associated
interest cost are included in the calculation of the weighted average interest
rate used for capitalizing interest on general funds. The primary debt
instruments included in the rate calculation are the Senior Notes and the $400
million corporate revolver. The capitalization rate for general corporate funds
excludes the Zero-Coupon Convertible Debentures, capital lease obligations,
bridge financings for acquisition purposes, cross-border financings not used for
construction purposes and other borrowings used for operating purposes.
4. Notes Receivable
As of September 30, 2001 and December 31, 2000, the components of notes
receivable were (in thousands):
SEPTEMBER 30, DECEMBER 31,
2001 2000
--------- ---------
PG&E note .............................. $ 105,630 $ 62,336
Delta note ............................. 271,759 112,050
Metcalf note ........................... 30,176 --
Other .................................. 46,634 43,724
--------- ---------
Total notes receivable ........ 454,199 218,110
Less: Notes receivable, current portion (10,523) (183)
--------- ---------
Notes receivable, net of current portion $ 443,676 $ 217,927
========= =========
9
Calpine Gilroy Cogen, LP ("Gilroy") had a long-term power purchase agreement
("PPA") with Pacific Gas and Electric Company ("PG&E") for the sale of energy
through 2018. The terms of the PPA provided for 120 megawatts of firm capacity
and up to 10 megawatts of as-delivered capacity. On December 2, 1999, the
California Public Utilities Commission approved the restructuring of the PPA
between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy
are each released from performance under the PPA effective November 1, 2002.
Under the restructured contract, in addition to the normal capacity revenue for
the period, Gilroy will earn from September 1999 to October 2002 restructured
capacity revenue it would have earned over the November 2002 through March 2018
time period, for which PG&E issues notes to the Company. These notes will be
paid by PG&E during the period from February 2003 to September 2014.
In 1999, the Company, together with Bechtel Enterprises ("Bechtel"), began the
development of an 880-megawatt gas-fired cogeneration project in Pittsburg,
California. As part of this joint venture, the Company has an interest bearing
note from the project, Delta Energy Center, LLC.
In 1999, the Company, together with Bechtel, began the development of a
579-megawatt gas-fired cogeneration project in San Jose, California. As part of
this joint venture, the Company has an interest bearing note from the project,
Metcalf Energy Center, LLC.
See Note 15 for a discussion of the Company's purchase of Bechtel's interests in
the Delta, Metcalf and Russell City Energy Centers.
5. Acquisitions and Asset Purchases
On July 10, 2001, the Company acquired the 500-megawatt natural gas-fired,
combined-cycle Otay Mesa Generating Project in San Diego County from the PG&E
National Energy Group. Construction began in September 2001 and completion is
scheduled for mid 2003. Under the terms of the sale, the Company will build, own
and operate the facility, and PG&E National Energy Group will contract for up to
250 megawatts of output. The balance of the output will be sold into the
California wholesale market through CES.
On August 15, 2001, the Company acquired approximately 86% of the voting stock
of Michael Petroleum Corporation, a Houston, Texas-based natural gas exploration
and development company, for $273.6 million and the assumption of $54.5 million
of debt. The acquisition includes 204 billion cubic feet equivalent of proven
natural gas reserves currently producing 43 mmcfe per day and an inventory of
drilling locations within a 94,000 acreage position in close proximity to the
South Texas Magic Valley and Hidalgo Energy Centers. See Note 15 for a
discussion of the Company's purchase of the remaining interest in Michael
Petroleum Corporation.
On August 24, 2001, the Company acquired and assumed operations of the Saltend
Energy Centre, a 1,200-megawatt natural gas-fired power plant located at Saltend
near Hull, Yorkshire, England. The Company purchased the cogeneration facility
from an affiliate of Entergy Corporation for L562.5 million (US$814.4 million at
exchange rates at the closing of the acquisition). The Saltend Energy Centre
began commercial operation in November 2000 and is one of the largest natural
gas-fired electric power generating facilities in England. Saltend provides
electricity and steam for BP Chemicals' Hull Works plant under the terms of a
15-year agreement. The balance of the plant's output is sold into the
deregulated United Kingdom power market.
On September 12, 2001, the Company purchased the remaining 33.3% interests in
the 247-megawatt Hog Bayou Energy Center and the 213-megawatt Pine Bluff Energy
Center from Houston, Texas-based Intergen (North America), Inc. for
approximately $9.6 million.
On September 20, 2001, the Company's wholly owned subsidiary, Canada Power
Holdings Ltd., acquired and assumed operations of two Canadian power generating
facilities from British Columbia-based Westcoast Energy Inc. for C$333.1 million
(US$212.1 million at exchange rates at the closing of the acquisition). The
Company acquired a 100% interest in the Island Cogeneration facility, a
250-megawatt natural gas-fired electric generating facility in the commissioning
phase of construction and located near Campbell River, British Columbia on
Vancouver Island. This facility will provide electricity to BC Hydro under the
terms of a 20-year agreement and steam to Norske Skog under the terms of a
15-year agreement. The Company also acquired a 50% interest in the 50-megawatt
Whitby Cogeneration facility located in Whitby, Ontario. This facility delivers
electricity to Ontario Energy Financial Corporation under the terms of a 20-year
agreement and provides steam to Atlantic Packaging.
6. Financing
10
The Company drew $838.3 million on the Calpine Construction Finance Company debt
revolvers during the quarter, which brought the Company's outstanding draws to
$2.5 billion.
During the third quarter, the Company borrowed a total of $1.2 billion under
three bridge credit facilities to finance several acquisitions (see Note 5).
These facilities were refinanced with long-term Senior Notes in the fourth
quarter of 2001. See Note 15 for further discussion.
7. Equity
On July 26, 2001, the Company filed amended certificates with the Delaware
Secretary of State to increase the number of authorized shares of common stock
to 1,000,000,000 from 500,000,000 and the number of authorized shares of Series
A Participating Preferred Stock to 1,000,000 from 500,000.
8. Derivative Instruments
As an independent power producer primarily focused on generation of electricity
using gas-fired turbines, our natural physical commodity position is "short" (we
require) gas and "long" (we own) power capacity. To manage forward exposure to
price fluctuation in these and (to a lesser extent) other commodities, we enter
into derivative commodity instruments. All transactions are subject to our risk
management policy which prohibits positions that exceed production capacity and
fuel requirements. Any hedging, balancing or optimization activities that we
engage in are directly related to our asset-based business model of owning and
operating gas-fired electric power plants. We hedge exposures that arise from
the ownership and operation of power plants and related sales of electricity and
purchases of natural gas, and we utilize derivatives to optimize the returns we
are able to achieve from these assets for our shareholders. This model is
markedly different from that of companies that engage in commodity trading
operations that are unrelated to underlying physical assets. Derivative
commodity instruments are accounted for under the requirements of SFAS No. 133.
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Company currently holds five classes of
derivative instruments that are impacted by the new pronouncement - interest
rate swaps, forward interest rate agreements, commodity financial instruments,
commodity contracts, and physical options. Additionally, one of the Company's
unconsolidated investees holds two foreign exchange forward contracts.
The Company enters into various interest rate swap agreements to hedge against
changes in floating interest rates on certain of its project financing
facilities. The interest rate swap agreements effectively convert floating rates
into fixed rates so that the Company can predict with greater assurance what its
future interest costs will be and protect itself against increases in floating
rates.
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 commodity financial instruments to convert floating or
indexed electricity and gas (and to a lesser extent oil and refined product)
prices to fixed prices in order to lessen its vulnerability to reductions in
electric prices for the electricity it generates, to reductions in gas prices
for the gas it produces, and to increases in gas prices for the fuel it consumes
in its power plants. The Company seeks to "self-hedge" its gas consumption
exposure to the maximum extent with its gas production position.
The Company routinely enters into commodity contracts for sales of its generated
electricity and sales of its natural gas production to ensure favorable
utilization of generation and production assets. Such contracts often meet the
criteria of SFAS No. 133 as derivatives but are generally eligible for the
normal purchase and sales exception under SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - An Amendment of FASB
Statement No. 133." For those that are not deemed normal purchases and sales,
most can be designated as hedges of the underlying production of gas or
electricity.
The Company also enters into physical options for short-term periods (typically
one month) to balance its short-term generating position. The options, which the
Company may write or purchase, typically provide for a premium component and
firm price for energy when exercised.
Upon adoption of SFAS No. 133, the fair values of all derivative instruments
were recorded on the balance sheet as assets or liabilities. The fair value of
derivative instruments is based on present value adjusted quoted market prices
of comparable contracts. For derivative instruments that were designated as
hedges, the difference between the carrying values of the derivatives and their
fair values at the date of adoption was recorded as a transition adjustment. At
adoption, such derivatives were designated as cash flow hedges and were deemed
highly effective. Accordingly, a transition adjustment was recorded to
accumulated other comprehensive income ("OCI"). In the case of capacity sales
contracts, a transition adjustment was recorded to earnings as a gain from the
cumulative effect of a change in accounting principle.
At the end of each quarter, the changes in fair values of derivative instruments
designated as cash flow hedges are recorded in OCI for the effective portion and
in current earnings, using the dollar offset method, for the ineffective
portion. The changes in fair values of derivative instruments designated as fair
value hedges are recorded in current earnings, as are the changes in fair values
of the
11
contracts being hedged. The changes in fair values of derivative instruments
that are not designated as hedges are recorded in current earnings.
On June 27, 2001, the FASB cleared SFAS No. 133 Implementation Issue No. C15
dealing with a proposed electric industry normal purchases and sales exception
for capacity sales transactions ("The Eligibility of Option Contracts in
Electricity for the Normal Purchases and Normal Sales Exception"). On October
10, 2001, the FASB revised the criteria for qualifying for the "normal"
exception. As a result of Issue No. C15, as revised, the Company expects that
certain of its existing and future capacity sales contracts will qualify for the
normal purchases and sales exception.
The table below reflects the amounts (in thousands) that are recorded as assets,
liabilities and in OCI at September 30, 2001 for the Company's derivative
instruments:
INTEREST RATE COMMODITY TOTAL
DERIVATIVE DERIVATIVE DERIVATIVE
INSTRUMENTS INSTRUMENTS INSTRUMENTS
------------ --------------- --------------
Current derivative asset (1)....................................... $ -- $ 663,840 $ 663,840
Long-term derivative asset (2)..................................... -- 541,898 541,898
------------- --------------- --------------
Total assets.................................................... $ -- $ 1,205,738 $ 1,205,738
============= =============== ==============
Current derivative liability (3)................................... $ 18,995 $ 725,327 $ 744,322
Long-term derivative liability (4)................................. 56,476 600,840 657,316
------------- --------------- --------------
Total liabilities............................................. $ 75,471 $ 1,326,167 $ 1,401,638
============== ================ ===============
Net derivative assets (liabilities)................................ $ (75,471) $ (120,429) $ (195,900)
============== ================ ===============
Total comprehensive loss........................................... $ (84,585) $ (354,011) $ (438,596)
Reclassification adjustment for activity included in net income.... 9,085 122,809 131,894
------------- --------------- --------------
Total pre-tax comprehensive loss from derivative instruments (5)... (75,500) (231,202) (306,702)
Income tax benefit................................................. 28,300 90,842 119,142
------------- --------------- --------------
Net comprehensive loss from derivative instruments............ $ (47,200) $ (140,360) $ (187,560)
============= =============== ==============
- ------------
(1) Included in other current assets.
(2) Included in other assets.
(3) Included in other current liabilities.
(4) Included in other liabilities.
(5) Represents total pre-tax comprehensive loss from derivatives, net of
amounts recognized in earnings during 2001. This figure is disclosed in
the first table in Note 9 as "Unrealized loss on cash flow hedges."
The table above presents the aggregate amounts of derivative assets,
liabilities, and OCI pertaining to derivatives as of September 30, 2001. Total
pre-tax comprehensive loss from derivative instruments represents the cumulative
effect on the Company's accumulated OCI balance from pre-tax losses from
effective cash flow hedges since the adoption of SFAS No. 133; it is not meant
to be a measurement of losses for the nine months ended September 30, 2001.
Because SFAS No. 133 was adopted in January 2001, the cumulative pre-tax OCI
balance from effective cash flow hedges is the same as for the nine months ended
September 30, 2001.
At any point in time, it is highly unlikely that total net derivative assets and
liabilities will equal cumulative pre-tax OCI from derivatives, for two primary
reasons:
- - Earnings effect of these derivatives -- Only derivatives that qualify as
effective cash flow hedges will have an offsetting amount recorded in OCI.
Derivatives not so designated 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.
- - Termination of effective cash flow hedges prior to maturity -- Following the
termination of a cash flow hedge and subsequent settlement with a counterparty,
the derivative asset or liability is liquidated and removed from the books. At
this point, no asset or liability exists on the books for the hedge but a
balance remains in OCI, which is amortized into earnings over the remaining
original life of the hedge as long as it is probable that the forecasted
transactions, or exposures that are being hedged, will occur. As a result,
12
there will be a temporary difference between OCI and derivative assets and
liabilities on the books until the remaining OCI balance is fully amortized into
earnings.
Below is a reconciliation from the Company's net derivative assets/liabilities
to its pre-tax comprehensive loss from derivative instruments at September 30,
2001 (in thousands):
Pre-tax comprehensive loss from derivative instruments ............... $(306,702)
Net derivative assets/(liabilities) .................................. (195,900)
---------
Difference ........................................................... $ 110,802
=========
Reconciliation:
Pre-tax earnings impact from derivatives not designated as
hedges and ineffective portion of derivatives designated
as hedges .......................................................... $ 110,662
Balances in OCI related to effective cash flow hedges terminated prior
to maturity, net of pre-tax amortization ........................... 140
---------
Total reconciling items .............................................. $ 110,802
=========
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: each of the two parties under contract owes the other
determinable amounts; 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;
the party reporting under the offset method intends to exercise its right to set
off; and; the right of set-off is enforceable by law. The table below reflects
both the amounts (in thousands) recorded as assets and liabilities by the
Company and the amounts that would have been recorded had the Company's
commodity derivative instrument contracts not qualified for offsetting as of
March 31, June 30, and September 30, 2001, respectively.
MARCH 31, 2001 JUNE 30, 2001 SEPTEMBER 30, 2001
-------------------------- ---------------------------- ---------------------------
GROSS NET GROSS NET GROSS NET
------------- ---------- ------------- ------------- ------------- ------------
Current Derivative Asset $ 1,000,129 $ 391,291 $ 2,304,337 $ 1,048,198 $ 2,800,765 $ 663,840
Long-Term Derivative Asset 290,237 162,488 1,359,347 874,306 1,956,502 541,898
------------- ---------- ------------- ------------- ------------- ------------
Total Derivative Assets $ 1,290,366 $ 553,779 $ 3,663,684 $ 1,922,504 $ 4,757,267 $ 1,205,738
============= ========== ============= ============= ============= ============
Current Derivative Liability $ 1,017,136 $ 408,297 $ 1,933,184 $ 677,045 $ 2,674,578 $ 725,327
Long-Term Derivative Liability 314,141 186,393 1,429,490 944,448 2,203,119 600,840
------------- ---------- ------------- ------------- ------------- ------------
Total Derivative Liabilities $ 1,331,277 $ 594,690 $ 3,362,674 $ 1,621,493 $ 4,877,697 $ 1,326,167
============= ========== ============= ============= ============= ============
The table above excludes the value of interest rate derivative instruments.
During the three and nine months ended September 30, 2001, the Company
recognized gains (losses) on derivatives not designated as hedges of $13.6
million and $83.3 million, respectively, which were recorded in electric
generation and marketing revenue, and $(4.1) million and $30.4 million,
respectively, which were recorded in fuel expense.
During the three and nine months ended September 30, 2001, the Company
recognized pre-tax gains (losses) of $49,748 and $(3.4) million, respectively,
related to hedge ineffectiveness on gas and crude oil contracts, which are
included in fuel expense. For the three and nine months ended September 30,
2001, the Company recognized no gains or losses related to hedge ineffectiveness
on electricity contracts. During the three and nine months ended September 30,
2001, the Company excluded from the assessment of hedge effectiveness the
extrinsic values of certain options used in costless collar arrangements to
hedge its crude oil production. The Company recorded a gain of $2.4 million for
the three and nine month periods ended September 30, 2001 associated with the
extrinsic value of these options. The Company excluded no components of any
other derivative instruments in assessing hedge effectiveness.
During the quarters ended March 31, 2001, June 30, 2001, and September 30, 2001,
the Company's realized pre-tax commodity cash flow hedge activity contributed
$17.0 million, $4.8 million, and $101.0 million to earnings respectively based
on the reclassification adjustment from OCI to earnings. For the quarter ended
September 30, 2001, power hedges contributed $126.9 million to earnings. At the
time the power hedges were sold, the market price for the contracted delivery
period was significantly higher than the market price when delivery actually
occurred. For the quarter ended September 30, 2001, gas hedges reduced earnings
by $25.9 million. At
13
the time the gas hedges were purchased, the market price for the contracted
delivery period was significantly higher than the market price when delivery
actually occurred.
As of September 30, 2001, the maximum length of time over which the Company is
hedging its exposure to the variability in future cash flows for forecasted
transactions is 17 years. The Company estimates that pretax gains related to the
transition adjustment associated with the adoption of SFAS No. 133 of $8.5
million will be reclassified from accumulated OCI into earnings during the next
three months. For derivative contracts entered into after January 1, 2001, the
Company estimates that pretax gains of $87.9 million will be reclassified from
accumulated OCI into earnings during the next twelve months as the hedged
transactions affect earnings.
See the Form 8-K filed on September 5, 2001 for a further discussion of the
Company's accounting policies related to derivative accounting.
9. Comprehensive Income
Comprehensive income is the total of net income and all other non-owner changes
in equity. Comprehensive income includes net income and unrealized gains and
losses from derivative instruments that qualify as hedges. The Company reports
accumulated other comprehensive income (loss) in its consolidated balance sheet.
In the table below, other comprehensive loss represents the total of all of the
Company's components of OCI for the current year as of September 30, 2001. The
Company's OCI components are: (i) unrealized pre-tax gains/losses, net of
reclassification-to-earnings adjustments, from effective cash flow hedges; (ii)
unrealized pre-tax gains/losses that result from the translation of foreign
subsidiaries' balance sheets from the foreign functional currency (primarily
Cdn.$) to the Company's consolidated reporting currency (US$); and (iii) the
taxes associated with the unrealized gains/losses from items (i) and (ii). Total
comprehensive income is summarized as follows (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------- --------------------------------
2001 2000 2001 2000
------------- ------------ ------------- -------------
Net income..................................... $ 320,799 $ 157,310 $ 548,127 $ 237,919
------------- ------------ ------------- -------------
Other comprehensive income:
Unrealized loss on cash flow hedges (1)... (479,490) -- (306,702) --
Loss on foreign currency translation...... (18,330) (5,570) (20,186) (5,570)
Income tax benefit........................ 196,249 2,105 126,813 2,105
------------- ------------ ------------- -------------
Other comprehensive loss, net of tax... (301,571) (3,465) (200,075) (3,465)
------------- ------------- ------------- -------------
Total comprehensive income..................... $ 19,228 $ 153,845 $ 348,052 $ 234,454
============= ============ ============= =============
- -----------------------
(1) Represents total pre-tax comprehensive loss from derivatives, net of
amounts recognized in earnings, for the three and nine months ended
September 30, 2001. This figure is disclosed in the first table in Note
8 as "Total pre-tax comprehensive loss from derivative instruments."
The total comprehensive income of $348.1 million for the nine months ended
September 30, 2001 represents the net of the Company's net income for the period
of $548.1 million and its unrealized OCI losses of $200.1 million. The
accumulated other comprehensive loss of $223.2 million, as reported within
Stockholders' Equity on the Company's balance sheet, is the sum of the current
year's unrealized OCI loss of $200.1 million and the ending OCI balance at
December 31, 2000 of $23.1 million. Prior to the current reporting year, all
items affecting the Company's accumulated OCI balance resulted from the
translation of its Canadian subsidiaries' balance sheets into U.S. dollars and
the corresponding tax effects thereon.
Under the reporting guidance of SFAS No. 130, "Reporting Comprehensive Income,"
unrealized gains/losses from foreign currency translation are not viewed as
deferred losses. As a result, from the total accumulated OCI loss at September
30, 2001 of $223.2 million, only the losses pertaining to cash flow hedges will
be recognized in earnings in future periods. As disclosed in Note 8, these
losses total $306.7 million on a pre-tax basis and $187.6 million net of tax.
Below is a reconciliation of the Company's pre-tax comprehensive loss from
derivatives (as disclosed in Note 8) to the accumulated other comprehensive loss
at September 30, 2001 (in thousands):
14
Pre-tax comprehensive loss from derivatives ........................ $(306,702)
Accumulated other comprehensive loss ............................... (223,160)
---------
Difference ......................................................... $ 83,542
=========
Reconciliation:
Less: Accumulated other comprehensive loss at December 31, 2000 (1) $ (23,085)
Less: Pre-tax loss on foreign currency translation from
1/1/01 - 9/30/01 ................................................. (20,186)
Add: OCI tax benefit from unrealized loss on cash flow
hedges from 1/1/01 - 9/30/01 (2), (3) ............................ 119,142
Add: OCI tax benefit from loss on foreign currency
translation from 1/1/01 - 9/30/01 (3) ............................ 7,671
---------
Total Reconciling Items ............................................ $ 83,542
=========
- ------------
(1) Accumulated other comprehensive loss at December 31, 2000 is deducted
because prior to January 1, 2001, there were no OCI balances related to
cash flow hedges.
(2) OCI tax benefit from unrealized loss on cash flow hedges of $119,142 is
disclosed in Note 8.
(3) The sum of the OCI tax benefits from unrealized loss on cash flow
hedges and loss on foreign currency translation is $126,813, which is
disclosed above in this Note 9.
10. Purchased Power and Gas Sales and Expense
The Company records the cost of gas consumed in its power plants as fuel
expense, while gas purchased from third parties for hedging, balancing and
related activities is recorded as the cost of gas purchased and resold, a
component of oil and gas production and marketing expense. The Company records
the actual revenue received from third parties as sales of purchased gas, a
component of oil and gas production and marketing revenue.
The cost of power purchased from third parties, for hedging, balancing and
optimization activities, along with the subsequent settlement of contracts that
have been previously recorded in results of operations as mark-to-market gains
or losses, is recorded as purchased power expense, a component of electric
generation and marketing expense. The Company markets on a system basis both
power generated by its plants in excess of amounts under direct contract between
the plant and a third party, and power purchased from third parties.
The table below shows the relative levels and growth of purchased power sales
and expense and purchased gas sales and expense activity (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ -----------------------------
2001 2000 2001 2000
------------- -------------- -------------- -------------
Sales of purchased power............. $ 2,028,280 $ 55,525 $ 3,165,078 $ 96,646
Sales of purchased gas............... 56,917 9,985 412,782 26,316
------------- --------- ------------- -----------
Total...................... $ 2,085,197 $ 65,510 $ 3,577,860 $ 122,962
============= ========= ============= ===========
Purchased power expense.............. $ 1,764,531 $ 54,058 $ 2,876,119 $ 96,910
Purchased gas expense................ 52,856 9,423 389,814 24,642
------------- --------- ------------- -----------
Total....................... $ 1,817,387 $ 63,481 $ 3,265,933 $ 121,552
============= ========= ============= ===========
The amounts shown in the final table of Note 9 above do not reflect the impact
of all realized gains and losses from changes in the fair market value of
mark-to-market power and gas commodities. The table below sets forth the
subcategories that comprise the electric generation and marketing revenue and
expense, the oil and gas production and marketing revenue and expense and the
fuel expense line items of the income statement.
15
THREE MONTHS NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- -----------------------------
2001 2000 2001 2000
------------- ---------- -------------- -------------
(IN THOUSANDS)
ELECTRIC GENERATION AND MARKETING REVENUE
Electricity and steam revenue..................................... $ 713,746 $ 588,257 $ 1,814,616 $ 1,094,815
Sales of purchased power.......................................... 2,028,280 55,525 3,165,078 96,646
Mark to market gains/(losses) on power derivatives................ 13,577 -- 83,316 --
------------- ---------- ------------- ------------
$ 2,755,603 $ 643,782 $ 5,063,010 $ 1,191,461
============= ========== ============= =============
OIL AND GAS PRODUCTION AND MARKETING REVENUE
Oil and gas sales to third parties................................ $ 82,465 $ 82,866 $ 355,471 $ 203,162
Sales of purchased gas............................................ 56,917 9,985 412,782 26,316
------------- ---------- ------------- -------------
$ 139,382 $ 92,851 $ 768,253 $ 229,478
============= ========== ============= =============
ELECTRIC GENERATION AND MARKETING EXPENSE
Plant operating expenses.......................................... $ 94,283 $ 53,151 $ 248,001 $ 132,754
Royalty expenses.................................................. 5,255 10,139 23,181 19,291
Purchased power expense........................................... 1,764,531 54,058 2,876,119 96,910
------------- ---------- ------------- -------------
$ 1,864,069 $ 117,348 $ 3,147,301 $ 248,955
============= ========== ============= =============
OIL AND GAS PRODUCTION AND MARKETING EXPENSE
Oil and gas production expenses................................... $ 18,360 $ 20,667 $ 79,951 $ 60,991
Purchased gas expense............................................. 52,856 9,423 389,814 24,642
------------- ---------- ------------- -------------
$ 71,216 $ 30,090 $ 469,765 $ 85,633
============= ========== ============= =============
FUEL EXPENSE
Cost of oil and natural gas burned by power plants................ $ 318,046 $ 185,619 $ 834,486 $ 363,315
Mark to market (gain)/loss on natural gas derivatives............. 4,054 -- (26,942) --
------------- ---------- ------------- ------------
$ 322,100 $ 185,619 $ 807,544 $ 363,315
============= ========== ============= =============
11. Significant Customers
The Company's significant customers at September 30, 2001 were certain
subsidiaries of Enron Corp. ("Enron") and PG&E.
Enron
In 2001 the Company, primarily through its CES subsidiary, has transacted a
significant volume of business with units of Enron. Most of these transactions
are contracts for sales and purchases of power and gas for hedging and
optimization purposes, some of which extend out as far as 2009. In October and
November of 2001, Enron announced a series of developments including restatement
of the last four years of earnings, an investigation by the Securities and
Exchange Commission relating to the adequacy of Enron's disclosures of certain
off-balance sheet financial transactions or structures and dismissals of certain
members of senior management. On December 2, 2001, Enron Corp. and certain of
its subsidiaries filed voluntary petitions for Chapter 11 reorganization with
The U.S. Bankruptcy Court for the Southern District of New York.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3%,
and $1,329.8 million or 22.7%, of the Company's revenue was with Enron
subsidiaries, primarily Enron Power Marketing, Inc. ("EPMI") and Enron North
America Corp. ("ENA"). ENA is the parent corporation of EPMI. Enron is the
direct parent corporation of ENA. EPMI and ENA are among the subsidiaries of
Enron that filed for reorganization on December 2, 2001. The Company, primarily
CES, purchases significant amounts of fuel and power from ENA and EPMI, giving
rise to current accounts payable and open contract fair value positions. These
purchases must be included in an overall understanding of the Company's Enron
exposure. For the three months ended September 30, 2001, CES had fuel and power
purchases from ENA and EPMI of $905.3 million. For the nine months ended
September 30, 2001, CES had fuel and power purchases from ENA and EPMI of
$1,358.7 million. The sales to and purchases from various Enron subsidiaries are
mostly hedging and optimization transactions, and in most cases the purchases
and sales are not related and should not be netted to try to gauge the
profitability of transactions with Enron subsidiaries.
The following table sets forth information regarding the Company's transactions
with Enron for the three and nine month periods ended September 30, 2001 (in
thousands of dollars and thousands of MWh's, in the case of electricity
transactions, and thousands of mmBTU's, in the case of oil and gas
transactions):
16
THREE MONTHS NINE MONTHS
ENDED ENDED
SEPTEMBER 30, 2001 SEPTEMBER 30, 2001
------------------------- ------------------------
DOLLAR VOLUME DOLLAR VOLUME
---------- ------- --------- ------
Electric generation and marketing revenue
(E&S revenues and sales of purchased power) $ 742,464 6,428 $1,155,736 11,293
Oil and gas production & marketing
Revenue (non-affiliated sales of
purchased gas) ............................. 22,833 7,825 169,758 26,048
Other revenue ................................ 2,580 4,275
---------- ----------
Total power and fuel revenue from Enron ...... $ 767,877 $1,329,769
========== ==========
Electric generation and marketing expense
(Purchased power expense) .................. $ 856,823 7,080 $1,222,025 10,481
Fuel expense (cost of oil and natural gas
burned by power plants) and mark to market
(gain)/loss on natural gas derivatives (cost
of gas purchased & resold) ................. 48,451 10,100 136,652 18,380
---------- ----------
Total CES power and fuel expenses
related to Enron(1) ........................ $ 905,274 $1,358,677
========== ==========
- ----------
(1) Expenses of CES only, as other Enron expenses incurred are not
material.
Unrealized pre-tax losses on derivatives designated as effective cash flow
hedges that were recorded in OCI associated with Enron activity at the quarters
ended March 31, 2001, June 30, 2001, and September 30, 2001 were $26.0 million,
$15.9 million, and $185.0 million, respectively. Recognized gains on derivatives
not designated as hedges associated with Enron activity were $39.9 million,
$226.7 million and $108.5 million for the quarters ended March 31, 2001, June
30, 2001 and September 30, 2001, respectively. Recognized losses on derivatives
not designated as hedges associated with Enron activity were $40.2 million,
$213.8 million and $140.2 million for the quarters ended March 31, 2001, June
30, 2001 and September 30, 2001, respectively. Recognized gross gains (losses)
on fair value hedges (which are perfectly offset by the gains and losses on the
hedged items) associated with Enron activity were $0.0 million, $(74.3) million
and $50.4 million dollars for the quarters ended March 31, 2001, June 30, 2001
and September 30, 2001, respectively. As of September 30, 2001, all of Calpine's
fair value hedges are 100% effective, so there is no net earnings impact from
these transactions.
On November 14, 2001, CES, ENA and EPMI entered into a Master Netting, Setoff
and Security Agreement (the "Netting Agreement"). The Netting Agreement permits
CES, on the one hand, and ENA and EPMI, on the other hand, to set off amounts
owed to each other under an ISDA Master Agreement between CES and ENA, an
Enfolio Master Firm Purchase/Sale Agreement between CES and ENA and a Master
Energy Purchase/Sale Agreement between CES and EPMI (in each case, after giving
effect to the netting provisions contained in each of these agreements).
Pursuant to the Netting Agreement, Enron's bankruptcy constituted an event of
default, and CES effected an early termination of the ISDA Master Agreement, the
Enfolio Master Agreement and the Master Energy Agreement on December 10, 2001.
CES is presently determining its losses, damages, attorneys' fees and other
expenses arising from the default by Enron and its affiliates, as it is entitled
to do pursuant to the underlying documents. The Company expects that there will
be a net amount payable to ENA pursuant to these agreements after giving effect
to the Netting Agreement, and thus that there will be no net credit exposure to
Enron and its affiliates arising from these transactions. The Company filed a
copy of the Netting Agreement as an exhibit to a Current Report on Form 8-K
dated November 14, 2001 and filed on January 16, 2002.
The Company believes that the Netting Agreement is enforceable in accordance
with its terms, based upon the following analysis, although there can be no
assurance in this regard. Section 553 of the Bankruptcy Code preserves the right
of a creditor who owes a debt to the debtor to offset that debt against a debt
owed by the debtor to the creditor, to the extent that such a right was in
existence between the parties prior to the bankruptcy. Setoff rights will be
preserved in bankruptcy, in general, where four conditions are met: (1) the
creditor has a claim against the debtor that arose before the bankruptcy case
was filed (a pre-petition claim); (2) the creditor owes a debt to the debtor
that also arose pre-petition;
17
(3) the claim and debt are mutual, meaning that the identical entities or
individual parties must each owe the other a debt in the same capacity; and (4)
the claim and debt are each valid and enforceable.
The Bankruptcy Code expressly permits the non-debtor party to certain types of
contracts, such as swap contracts and forward contracts, to terminate and
liquidate the contracts after the commencement of a bankruptcy case as the
result of a bankruptcy default. Section 556 provides, among other things, that
the contractual right of a forward contract merchant to cause the liquidation of
a forward contract pursuant to a bankruptcy termination clause will not be
stayed, avoided or otherwise limited by operation of any provision of the
Bankruptcy Code or by the order of any court in any proceeding under the
Bankruptcy Code. Similarly, Section 560 provides, among other things, that the
contractual right of any swap participant to cause the termination of a swap
agreement pursuant to a bankruptcy termination clause or to offset or net out
any termination values or payment amounts under or in connection with a swap
agreement shall not be stayed, avoided or otherwise limited by operation of any
provision of the Bankruptcy Code or by order of a court or administrative agency
in any proceeding under the Bankruptcy Code. Section 362(b)(6) of the Bankruptcy
Code authorizes the setoff of any mutual debts and claims arising from forward
contracts and securities contracts between a debtor and a non-debtor, and
362(b)(17) of any mutual debts arising from one or more swap agreements between
a debtor and a non-debtor. Finally, "swap agreement" is defined by Section
101(53B)(C) of the Bankruptcy Code to include any master agreement relating to
derivative instruments of the nature identified in that section (which includes
commodity derivatives).
The Company believes that the netting of debts and claims across the underlying
master agreements and the transactions entered into pursuant to the master
agreements, as provided for in the Netting Agreement, is entitled to the
benefits of the provisions of the Bankruptcy Code summarized above although
there can be no assurance in this regard. This conclusion is based not only on
the language of the relevant statutory provisions, but also the policy
underlying their adoption, which was to preserve the ability of counterparties
to derivative contracts to immediately net and close out their contracts in the
event of a bankruptcy. This is viewed as a beneficial way to mitigate systemic
risk that could otherwise arise in a bankruptcy where the presence of the
automatic stay, as well as the bankruptcy trustee's broad equitable powers with
respect to executory contracts, would cast significant doubt upon the ongoing
enforceability of derivative transactions. Separate and apart from these special
protections provided by the Bankruptcy Code for forward contracts and swap
agreements, the Netting Agreement and the netting provisions of the underlying
master agreements are formal written agreements that would in any event be
enforceable. The setoffs made by CES are often referred to as "triangular
setoffs". A triangular setoff is one where A seeks to offset an obligation it
owes to B against a debt that B owes to C. Here, a triangular setoff is one
where CES seeks to set off an obligation it owes to ENA against a debt that EPMI
owes to CES or, put another way, one where CES seeks to require the Enron
entities to aggregate their debts and claims for setoff purposes. While the
strict mutuality of Section 553 of the Bankruptcy Code is not present, if the
parties all agree in a pre-petition contract that a setoff may be taken between
A, B and C, then the agreement may be enforced in bankruptcy to the extent that
it is enforceable under applicable nonbankruptcy law. This exception is limited,
however, to cases where there is a formal pre-petition contract, such as the
Netting Agreement.
In addition to the written Netting Agreement, for nearly a year prior to the
bankruptcy filing by Enron and certain of its affiliates, CES and the Enron
entities offset and netted debts and claims under all of the forward contracts
and swap agreements among the parties pursuant to an oral agreement that was
relied upon. It is established that the "formal contract" required to establish
the right of setoff under the Bankruptcy Code need not be in writing, so long as
there is sufficient evidence indicating a definite understanding or agreement
between the debtor and the corporation seeking a setoff.
In assessing its exposure to Enron subsidiaries and affiliates, the Company
analyzes its accounts receivable and accounts payable balances on contracts that
have already settled and also the fair value (mark to market value) of the
contracts that have not settled. Following are the accounts receivable and
accounts payable balances, presented on both a gross and net basis, as well as
the gross and net fair values of the open contracts with Enron subsidiaries and
affiliates at November 29, 2001, which have been updated since the Form 8-K
dated November 28, 2001 and filed on December 3, 2001. The positive net
positions have realization exposure, while the negative net positions are
existing or potential obligations.
18
NET NET OPEN
GROSS GROSS RECEIVABLE GROSS FAIR GROSS FAIR POSITIONS
RECEIVABLE PAYABLE (PAYABLE) VALUE(+) VALUE(-) VALUE TOTAL
---------- ------- ---------- ---------- ----------- --------- ---------
Enron North America . $ 15.5 $ (16.6) $ (1.1) $1,803.1 $(2,105.0) $ (301.9) $ (303.0)
Enron Power Marketing 121.1 (96.7) 24.4 451.5 (328.6) 122.9 147.3
-------- -------- -------- -------- -------- -------- --------
Total ............. 136.6 (113.3) 23.3 2,254.6 (2,433.6) (179.0) (155.7)
Enron Canada ........ 1.9 -- 1.9 -- (18.5) (18.5) (16.6)
Citrus Trading Corp . -- (1.8) (1.8) 32.0 -- 32.0 30.2
Other ............... -- (0.4) (0.4) -- -- -- (0.4)
After netting the receivables and payables and the value of the open positions
from ENA and EPMI, CES has an existing or future obligation of $155.7 million
(the sum of the net receivable of $23.3 million and the net open positions value
of $(179.0) million) as of November 29, 2001, which obligation will be offset by
CES' losses, damages, attorneys' fees and other expenses arising from the
default by Enron. The Company has one contract to purchase gas from Citrus
Trading Corp ("Citrus"). El Paso Corporation, which owns 50% of Citrus, has
affirmed its commitment to continue all deliveries of gas to Citrus. As further
assurance, El Paso also stated it has the first option to purchase the remaining
50% of Citrus from Enron in the event Enron chooses to sell its share of Citrus.
Currently, Citrus has continued to deliver all gas as required under the
contract. The Company's Auburndale entity is the beneficiary of a guarantee by
El Paso of 50% of Citrus' payment obligations under the Citrus fuel supply
contract with Auburndale.
Based on the above, the Company had no net exposure to Enron at November 29,
2001. Additionally, the Company believes that its Citrus Trading Corp. exposure
is mitigated by the fact that its parent, Citrus Corp., is 50% owned by El Paso
Corporation. The Company has not established any reserve against Enron exposure.
The Company's treasury department includes a credit group focused on monitoring
and managing counterparty risk. The credit group monitors the net exposure with
each counterparty on a daily basis. The analysis is performed on a mark to
market basis using the forward curves audited by the Company's Risk Controls
group. The net exposure is compared against a counterparty credit risk threshold
which is determined based on the counterparty's credit ratings, evaluation of
the financial statements and bond values. The credit department monitors these
thresholds to determine the need for additional collateral or an adjustment to
activity with the counterparty.
The Company will continue to evaluate the Enron risk in the same manner as
discussed above. The Company will adjust its threshold for Enron exposure based
on factors discussed above and will continue to monitor the exposure on a daily
basis.
PG&E
The Company's northern California Qualifying Facility ("QF") subsidiaries sell
power to PG&E under the terms of long-term contracts at eleven facilities. On
April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the
United States Bankruptcy Code. PG&E is the regulated subsidiary of PG&E
Corporation, and the information on PG&E disclosed below excludes PG&E
Corporation's non-regulated subsidiary activity. The Company has transactions
with certain of the non-regulated subsidiaries, which have not been affected by
PG&E's bankruptcy. On July 12, 2001, the U.S. Bankruptcy Court for the Northern
District of California approved the agreement the Company had entered into with
PG&E to modify and assume all of Calpine's QF contracts with PG&E. Under the
terms of the agreement, the Company will continue to receive its contractual
capacity payments plus a five-year fixed energy price component that averages
5.37 cents per kilowatt-hour in lieu of the short run avoided cost. In addition,
all past due receivables under the QF contracts were elevated to administrative
priority status and will be paid to the Company, with interest, upon the
effective date of a confirmed plan of reorganization. On September 20, 2001,
PG&E filed its proposed plan of reorganization with the bankruptcy court.
The Company's QF contracts with PG&E provide that the California Public
Utilities Commission ("CPUC") has the authority to determine the appropriate
utility "avoided cost" to be used to set energy payments for certain QF
contracts, including those for all of the Company's QF plants in California
which sell power to PG&E. Section 390 of the California Public Utility Code
provides QFs the option to elect to receive energy payments based on the
California Power Exchange ("PX") market clearing price. In mid 2000, the
Company's QF facilities elected this option and were paid based upon the PX
zonal day ahead clearing price ("PX Price") from summer 2000 until January 19,
2001, when the PX ceased operating a day ahead market. Since that time, the CPUC
has ordered that the price to be paid for energy deliveries by QFs electing the
PX Price shall be based on a natural gas cost-based "transition formula." The
CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price
was the appropriate price for the energy component upon which to base payments
to QFs which had elected the PX-based pricing option. The CPUC has issued a
proposed decision to the effect that the PX price was the appropriate price for
energy payments under the California Public Utility Code. However, a final
decision has not been issued to date. Therefore, it is possible that the CPUC
could order a payment adjustment based
19
on a different energy price determination. The Company believes that the PX
Price was the appropriate price for energy payments, but there can be no
assurance that this will be the outcome of the CPUC proceedings.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March
2001 Decision") proposing to change, on a prospective basis, the composition of
the short run avoided cost ("SRAC") energy price formula, which is reset
monthly, used by the California utilities in QF contracts. Prior to the March
2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50%
Malin border gas indices. In the March 2001 Decision, the CPUC changed this
formulation to eliminate the prices at Topock from the SRAC formula. The March
2001 Decision is subject to challenges at the CPUC and the Federal Energy
Regulatory Commission ("FERC").
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the
"June 2001 Decision") that authorized the California utilities, including PG&E,
to amend QF contracts to elect a fixed energy price component that averages 5.37
cents per kilowatt-hour for a five-year term under those contracts in lieu of
using the SRAC energy price formula. By this order, the CPUC authorized the QF
contract energy price amendments without further CPUC concurrence. As part of
the agreement the Company entered into with PG&E pursuant to which PG&E, in
bankruptcy, agreed to assume its QF contracts with Calpine, PG&E agreed with the
Company to amend these contracts to adopt the fixed price component that
averages 5.37 cents pursuant to the June 2001 Decision. This election became
effective as of July 16, 2001. As a result of the June 2001 Decision and the
Company's agreement with PG&E to amend the QF contracts to adopt the fixed price
energy component, the energy price component in Calpine's QF contracts is now
fixed for five years and the Company is no longer subject to any uncertainty
that may have existed with respect to this component of Calpine's QF contract
pricing as a result of the March 2001 Decision. Further, the March 2001 Decision
has no bearing on PG&E's agreement with the Company to assume the QF contracts
in bankruptcy or on the amount of the receivable that was so assumed.
Revenues earned from PG&E for the three and nine months ended September 30, 2001
and 2000 were as follows (in thousands):
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2001 2000 2001 2000
-------- -------- -------- --------
Revenues:
PG&E .... $159,052 $203,894 $449,047 $342,923
PG&E receivables at September 30, 2001, April 6, 2001 (the date of PG&E's
bankruptcy filing), and December 31, 2000, were as follows (in thousands):
SEPTEMBER 30, 2001 APRIL 6, 2001 DECEMBER 31, 2000
------------------ ------------- -----------------
Receivables:
PG&E........ $292,055 $265,588 $204,448
Of the $292.1 million PG&E receivable balance at September 30, 2001, the
pre-petition balance of $265.6 million remains unreserved and is classified as a
long-term receivable. Through September 30, 2001, as a result of PG&E's decision
to assume its QF contracts with Calpine, the Company has recorded $6.0 million
of interest income which is included in the long-term receivable balance. PG&E
has paid and continues to pay currently for energy deliveries made after April
6, 2001.
The Company had a combined accounts receivable balance of $20.5 million as of
September 30, 2001 from the California Independent System Operator Corporation
("CAISO") and Automated Power Exchange, Inc. ("APX"). Of this balance, $10.0
million relates to past due balances prior to the PG&E bankruptcy filing. The
Company has provided a full reserve for these past due receivables. CAISO's
ability to pay the Company is directly impacted by PG&E's ability to pay CAISO.
APX's ability to pay the Company is directly impacted by PG&E's ability to pay
the PX, which in turn would pay APX for energy delivered by the Company through
APX. As noted above, the PX ceased operating in January 2001. See Note 15 for an
update on the FERC investigation into the California wholesale markets.
The Company also had an accounts receivable balance of $107.2 million at
September 30, 2001 from the California Department of Water Resources ("DWR").
Past due accounts receivable from the California Department of Water Resources
at September 30, 2001 totaled $14.4 million. This amount has been collected in
full. Payment of $13.7 million for test power sales was received on November 1,
2001. Payment of $702,350 for other test power sales was received on December
10, 2001. The Company accordingly has determined that there is no reserve
needed. The Company's sales to DWR are primarily pursuant to long term
contracts, so the Company has not had the same degree of collectibility problems
that some generators selling into the day-ahead market have experienced because
of administrative and/or political issues between the CAISO and DWR.
20
12. Earnings per Share
Basic earnings per common share were computed by dividing net income by the
weighted average number of common shares outstanding for the period. The
dilutive effect of the potential exercise of outstanding options to purchase
shares of common stock is calculated using the treasury stock method. The
dilutive effect of the assumed conversion of certain convertible securities into
the Company's common stock is based on the dilutive common share equivalents and
the after tax distribution expense avoided upon conversion. The reconciliation
of basic earnings per common share to diluted earnings per share is shown in the
following table (in thousands except per share data). All share data has been
adjusted to reflect the two-for-one stock split that became effective on
November 14, 2000.
PERIODS ENDED SEPTEMBER 30,
---------------------------------------------------------------------
2001 2000
--------------------------------- ---------------------------------
NET NET
INCOME SHARES EPS INCOME SHARES EPS
--------- --------- ---------- --------- --------- ----------
THREE MONTHS:
Basic earnings per common share:
Income before extraordinary charge and cumulative
effect of a change in accounting principle ............. $ 320,799 304,666 $ 1.05 $ 158,545 285,143 $ 0.56
Extraordinary charge, net of tax benefit ................. -- -- -- (1,235) -- (0.01)
Cumulative effect of a change in accounting principle,
net of tax ............................................. -- -- -- -- -- --
--------- --------- ---------- --------- --------- ----------
Net income ............................................... $ 320,799 304,666 $ 1.05 $ 157,310 285,143 $ 0.55
--------- --------- ---------- --------- --------- ----------
Common shares issuable upon exercise of stock options
using treasury stock method ............................ 13,886 17,096
--------- ---------
Diluted earnings per common share:
Income before dilutive effect of certain convertible
securities, extraordinary charge and cumulative effect
of a change in accounting principle .................... $ 320,799 318,552 $ 1.01 $ 158,545 302,239 $ 0.52
Dilutive effect of certain convertible securities ........ 12,470 58,153 (0.13) 7,696 39,573 (0.03)
--------- --------- ---------- --------- --------- ----------
Income before extraordinary charge and cumulative effect
of a change in accounting principle .................... 333,269 376,705 0.88 166,241 341,812 0.49
Extraordinary charge, net of tax benefit ................. -- -- -- (1,235) -- (0.01)
Cumulative effect of a change in accounting principle,
net of tax ............................................. -- -- -- -- -- --
--------- --------- ---------- --------- --------- ----------
Net income ............................................... $ 333,269 376,705 $ 0.88 $ 165,006 341,812 $ 0.48
--------- --------- ---------- --------- --------- ----------
NINE MONTHS:
Basic earnings per common share:
Income before extraordinary charge and cumulative
effect of a change in accounting principle ............. $ 548,391 302,649 $ 1.81 $ 239,154 275,392 $ 0.87
Extraordinary charge, net of tax benefit ................. (1,300) -- -- (1,235) -- (0.01)
Cumulative effect of a change in accounting principle,
net of tax ............................................. 1,036 -- -- -- -- --
--------- --------- ---------- --------- --------- ----------
Net income ............................................... $ 548,127 302,649 $ 1.81 $ 237,919 275,392 $ 0.86
--------- --------- ---------- --------- --------- ----------
Common shares issuable upon exercise of stock options
using treasury stock method ............................ 15,231 16,313
--------- ---------
Diluted earnings per common share:
Income before dilutive effect of certain convertible
securities, extraordinary charge and cumulative effect
of a change in accounting principle .................... $ 548,391 317,880 $ 1.73 $ 239,154 291,705 $ 0.82
Dilutive effect of certain convertible securities ........ 33,204 52,353 (0.16) 15,373 31,338 (0.03)
--------- --------- ---------- --------- --------- ----------
Income before extraordinary charge and cumulative effect
of a change in accounting principle .................... 581,595 370,233 1.57 254,527 323,043 0.79
Extraordinary charge, net of tax benefit ................. (1,300) -- -- (1,235) -- (0.01)
Cumulative effect of a change in accounting principle,
net of tax ............................................. 1,036 -- -- -- -- --
--------- --------- ---------- --------- --------- ----------
Net income ............................................... $ 581,331 370,233 $ 1.57 $ 253,292 323,043 $ 0.78
========= ========= ========== ========= ========= ==========
21
Unexercised employee stock options to purchase approximately 2,683,858 and
134,820 shares of the Company's common stock during the nine months ended
September 30, 2001 and 2000, respectively, were not included in the computation
of diluted shares outstanding because such inclusion would have been
anti-dilutive.
13. Commitments and Contingencies
Capital Expenditures -- During the third quarter of 2001, the Company entered
into commitments for 12 steam turbine generators from Siemens Westinghouse, one
steam turbine generator from Fuji and three combustion turbine generators from
Siemens Westinghouse. The above brought the total number of combustion and steam
turbines on order to 320 with an approximate value of $9.7 billion, which
includes turbines delivered to projects under construction.
Litigation -- An action was filed against Lockport Energy Associates, L.P.
("Lockport") and the New York Public Service Commission ("NYPSC") in August 1997
by New York State Electricity and Gas Company ("NYSEG") in the Federal District
Court for the Northern District of New York. NYSEG requested the Court to direct
NYPSC and FERC to modify contract rates to be paid to the Lockport Power Plant.
In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the
Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and the
Federal Power Act by failing to reform the NYSEG contract that was previously
approved by the NYPSC. On September 29, 2000, the New York Federal District
Court dismissed NYSEG's complaint and NYPSC's cross-claim. The Court stated that
FERC has no authority to alter or waive its regulations or exemptions to alter
the terms of the applicable power purchase agreements and that Qualifying
Facilities are entitled to the benefit of their bargain, even if at the expense
of NYSEG and its ratepayers. NYSEG has filed an appeal with respect to this
decision. In any event, the Company retains the right to require The Brooklyn
Union Gas Company to purchase its interest in the Lockport Power Plant for $18.9
million, less equity distributions received by the Company, at any time before
December 19, 2001. On October 5, 2001, the United States Court of Appeals
affirmed the judgment of the federal district court and dismissed all of the
claims raised by NYSEG against Lockport.
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse effect on the Company's financial
position or results of operations.
14. Operating Segments for the Three and Nine Months Ended September 30, 2001
The Company's primary operating segments are electric generation and marketing;
oil and gas production and marketing; and corporate activities and other.
Electric generation and marketing includes the development, acquisition,
ownership and operation of power production facilities, the sale of electricity
and steam and electricity hedging and related activity. Oil and gas production
and marketing includes the ownership and operation of gas fields, gathering
systems and gas pipelines for internal gas consumption, third party sales and
oil and gas hedging and related activity. Corporate activities and other
consists primarily of financing activities, general and administrative costs and
consolidating eliminations. Certain costs related to company-wide functions are
allocated to each segment. However, interest on corporate debt is maintained at
corporate and is not allocated to the segments. Due to the integrated nature of
the business segments, estimates and judgments have been made in allocating
certain revenue and expense items. The Company evaluates performance of these
operating segments based upon several criteria including profits before tax.
22
ELECTRIC OIL AND GAS
GENERATION PRODUCTION CORPORATE
AND MARKETING AND MARKETING AND OTHER TOTAL
---------------------- ---------------------- ----------------------- ----------------------
2001 2000 2001 2000 2001 2000 2001 2000
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
For the three months ended
September 30, 2001 and 2000:
Revenues ......................... $2,765,101 $ 651,336 $ 155,191 $ 114,635 $ (4,187) $ (21,157) $2,916,105 $ 744,814
Income before taxes and
extraordinary charge ............. 470,545 258,484 15,656 38,934 (21,195) (32,392) 465,006 265,026
For the nine months ended
September 30, 2001 and 2000:
Revenues ......................... $5,077,435 $1,213,857 $ 869,002 $ 262,849 $ (77,708) $ (29,538) $5,868,729 $1,447,168
Merger expense ................... -- -- 41,627 -- -- -- 41,627 --
Income before taxes, extraordinary
charge and cumulative effect of
a change in accounting principle 776,687 414,432 187,376 66,310 (112,635) (79,161) 851,428 401,581
ELECTRIC OIL AND GAS
GENERATION PRODUCTION CORPORATE
AND MARKETING AND MARKETING AND OTHER TOTAL
------------- ------------- ------------- -------------
(IN THOUSANDS)
Total assets:
September 30, 2001...... $ 8,454,410 $ 3,236,573 $ 7,118,301 $18,809,284
For the three months ended September 30, 2001 and 2000, there were intersegment
revenues of approximately $15.9 million and $22.1 million, respectively. For the
nine months ended September 30, 2001 and 2000, there were intersegment revenues
of approximately $100.8 million and $33.9 million, respectively. The elimination
of these intersegment revenues, which primarily relate to the use of internally
procured gas for the Company's power plants, are included in the Corporate and
Other reporting segment.
15. Subsequent Events
FERC Investigation into California Wholesale Markets -- FERC ordered all sellers
and buyers in wholesale power markets administered by the California ISO, as
well as representatives of the State of California, to participate in a
settlement conference before a FERC administrative judge. The settlement
discussions were intended to resolve all issues that remain outstanding to
resolve past accounts, including sellers' claims for unpaid invoices, and
buyers' claims for refunds of alleged overcharges, for past periods. The
settlement discussions began on June 25, 2001, and ended on July 9, 2001. The
Chief Administrative Law Judge issued his report and recommendations to FERC on
July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing
to calculate refunds for spot market transactions in California. The hearing has
been delayed pending the submission by the California ISO and the California
Power Exchange of data for the purpose of developing the factual basis needed to
implement the refund methodology and order refunds. The FERC Administrative Law
Judge presiding over this hearing recently announced that this information must
be submitted not later than December 7, 2001, and the deadline for completion of
the hearing is March 8, 2002. While it is not possible to predict the amount of
any refunds until the hearings take place, based upon the information available
at this time, the Company does not believe that this proceeding will result in a
material adverse effect on the Company's financial position or results of
operations.
Other Subsequent Events
On October 2, 2001, the Company announced that Moody's Investors Service
upgraded the Company's corporate and credit and senior unsecured notes rating to
Baa3, which is investment grade rating, from Ba1. Moody's downgraded the
Company's corporate credit and senior unsecured note rating to Ba1 on December
14, 2001. Fitch lowered the Company's senior unsecured debt rating to BB+ on
December 19, 2001.
On October 16, 2001, the Company acquired California Energy General Corporation
and CE Newburry, Inc. from MidAmerican Energy Holdings Company for an
undisclosed amount. The transaction includes the companies' geothermal resource
assets, contracts, leases and development opportunities associated with the
Glass Mountain Known Geothermal Resource Area ("Glass Mountain KGRA") located in
Siskiyou County, California, approximately 30 miles south of the Oregon border.
These purchases are directly related to the Company's plans to develop the
49.5-megawatt Fourmile Hill Geothermal Project located in the Glass Mountain
KGRA.
23
The Fourmile Hill project is in advanced development and is projected to be
online by late 2004. Power from the project is committed to the Bonneville Power
Administration ("BPA") under a 20-year contract and will be delivered within
BPA's northern California service territory.
On October 16, 2001, the Company completed offerings of $530 million in
aggregate principal amount of 8.500% Senior Notes Due 2008 issued by Calpine
Canada Energy Finance ULC and guaranteed by the Company (a reopening of senior
notes previously issued in April 2001), and $850 million in aggregate principal
amount of 8.500% Senior Notes Due 2011 issued by the Company directly (a
reopening of senior notes previously issued in February 2001).
On October 18, 2001, the Company completed an offering of C$200 million in
aggregate principal amount of 8.750% Senior Notes Due 2007 issued by its wholly
owned subsidiary Calpine Canada Energy Finance ULC and guaranteed by the
Company, and completed offerings of L200 million in aggregate principal amount
of 8.875% Senior Notes Due 2011 and E175 million in aggregate principal amount
of 8.375% Senior Notes Due 2008 issued by its wholly owned subsidiary Calpine
Canada Energy Finance II ULC and guaranteed by the Company. Proceeds from the
offerings will be used to refinance existing bridge loan financings incurred to
fund recently completed transactions, finance the development and construction
of additional power generation facilities and for working capital and general
corporate purposes.
On October 18, 2001, the Company completed sale/leaseback transactions for the
Southpoint, Broad River and RockGen facilities raising $800.0 million in
sale/leaseback proceeds. In connection with these transactions, Calpine
Corporation provided a guarantee for the obligations under the leases. The
lessors issued lessor notes with an aggregate principal amount of $654.5
million, which was funded by the proceeds from the issuance of pass through
certificates. In effect, the pass through certificates evidence the debt
component of these sale/leaseback transactions. The pass through certificates
were issued in two tranches: the first, consisting of $454.5 million in
aggregate principal amount of 8.4% Series A Certificates due May 30, 2012, and
the second, consisting of $200 million in aggregate principal amount of 9.825%
Series B Certificates due May 30, 2019. Proceeds from the sale/leasebacks will
be used to refinance outstanding borrowings under the Company's construction
loan facilities, certain project-specific debt and other indebtedness, and for
working capital and general corporate purposes.
October 22, 2001, the Company acquired the remaining 14% of the voting stock of
Michael Petroleum Corporation for approximately $41.9 million.
On November 5, 2001, the Company acquired Highland Energy Company from Entergy
Power Gas Operations Corporation and Louis Morrison III for an undisclosed
amount.
On November 6, 2001, the Company acquired Bechtel Enterprises Holdings, Inc.'s
50% interest in the Delta Energy Center, the Metcalf Energy Center and the
Russell City Energy Center for approximately $154 million and the assumption of
approximately $141 million of debt.
On December 2, 2001, Enron Corp., a significant customer, filed for bankruptcy
(See Note 11).
ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Except for historical financial information contained herein, the matters
discussed in this quarterly report may be considered "forward-looking"
statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended,
including statements regarding the intent, belief or current expectations of
Calpine Corporation (the "Company") and its management. 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 materially affect actual
results such as, but not limited to, (i) the timing and extent of deregulation
of energy markets and the rules and regulations adopted on a transitional basis
with respect thereto, (ii) the timing and extent of changes in commodity prices
for energy, particularly natural gas and electricity, (iii) commercial
operations of new plants that may be delayed or prevented because of various
development and construction risks, such as a failure to obtain financing and
the necessary permits to operate or the failure of third-party contractors to
perform their contractual obligations, (iv) unseasonable weather patterns that
reduce demand for power, (v) systemic economic slowdowns, which can adversely
affect consumption of power by businesses and consumers, (vi) cost estimates are
preliminary and actual costs may be higher than estimated, (vii) a competitor's
development of lower-cost generating gas-fired power plant, (viii) risks
associated with marketing and selling power from power plants in the
newly-competitive energy market, (ix) risks associated with engineering,
designing, manufacturing and marketing combustion turbine parts and components,
(x) delivery and performance risks associated with combustion turbine parts and
components attributable to production, quality control, suppliers and
transportation or (x) the successful exploitation of an oil or
24
gas resource that ultimately depends upon the geology of the resource, the total
amount and cost to develop recoverable reserves, and operational factors
relating to the extraction of natural gas. You are also cautioned that the
California energy market remains uncertain. The Company's management is working
closely with a number of parties to resolve the current uncertainty. This is an
ongoing process and therefore, the outcome cannot be predicted. It is possible
that any such outcome will include changes in government regulations, business
and contractual relationships or other factors that could materially affect the
Company, however, the Company believes that a final resolution of the situation
in the California energy market will not have a material adverse impact on the
Company. You are also referred to the other risks identified from time to time
in the Company's reports and registration statements filed with the Securities
and Exchange Commission.
Selected Operating Information
Set forth below is certain selected operating information for our power plants
and steam fields, for which results are consolidated in our statements of
operations. Results vary for the three and nine months ended September 30, 2001,
respectively, as compared to the same periods in 2000, primarily due to the
consolidation of acquisitions and increased production. The results for the nine
months ended September 30, 2001, as compared to the same period in 2000,
benefited from favorable energy pricing. Electricity revenue is composed of
fixed capacity payments, which are not related to production, and variable
energy payments, which are related to production. Capacity revenue includes,
besides traditional capacity payments, other revenues such as reliability must
run and ancillary service revenues. The information set forth under thermal and
other revenue consists of host thermal sales and other revenue (revenues in
thousands.
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ ------------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
Adjusted electricity and
steam ("E&S") revenues:
Energy (1) ................. $ 754,674 $ 400,448 $ 1,561,227 $ 725,777
Capacity ................... $ 179,482 $ 154,893 $ 424,805 $ 299,694
Thermal and other .......... $ 43,339 $ 34,383 $ 117,544 $ 69,079
Megawatt hours generated ... 13,687,401 7,049,078 28,804,105 16,108,267
All-in electricity price per
megawatt hour generated .... $ 71.42 $ 83.66 $ 73.03 $ 67.95
- ------------
(1) Adjusted to include spread on sales of purchased power (See Note 10).
Megawatt hours produced at the power plants increased 94% and 79% for the three
and nine months ended September 30, 2001, respectively, as compared to the same
periods in 2000. This was primarily due to the addition of power plants that
were either acquired or commenced commercial operation subsequent to September
30, 2000.
Results of Operations
Set forth below is a table summarizing the dollar amounts and percentages of our
total revenue for the three and nine month periods ended September 30, 2001 and
2000 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 for percentage data):
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ ------------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
Total revenue .................. $2,916,105 $ 744,814 $5,868,729 $1,447,168
Sales of purchased power ....... 2,028,280 55,525 3,165,078 96,646
As a percentage of total revenue 69.6% 7.5% 53.9% 6.7%
Sale of purchased gas .......... 56,917 9,985 412,782 26,316
As a percentage of total revenue 2.0% 1.3% 7.0% 1.8%
Total cost of revenue ("COR") .. 2,380,214 418,555 4,753,045 903,126
Purchased power expense ........ 1,764,531 54,058 2,876,119 96,910
As a percentage of total COR ... 74.1% 12.9% 60.5% 10.7%
Purchased gas expense .......... 52,856 9,423 389,814 24,642
As a percentage of total COR ... 2.2% 2.3% 8.2% 2.7%
The primary reasons for the significant increase in these sales and cost of
revenue activities in 2001 as compared with 2000 are: (a) the growth of Calpine
Energy Services ("CES") in 2001 as compared with 2000 and the corresponding
increase in hedging, balancing and optimization activities; (b) particularly
volatile markets and high prices for electricity and natural gas, which prompted
us to
25
frequently adjust our hedge positions by buying power and gas and reselling it;
(c) the accounting requirements under SAB 101 and EITF 99-19, 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 throughout 2001 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 treatment increases revenues but not gross
profit.
Three Months Ended September 30, 2001, Compared to Three Months Ended September
30, 2000
Revenue -- Total revenue increased to $2,916.1 million for the three months
ended September 30, 2001, compared to $744.8 million for the same period in
2000.
Electric generation and marketing revenue increased to $2,755.6 million in
2001 compared to $643.8 million in 2000. Approximately $125.5 million of
the $2,111.8 million variance was due to electricity and steam sales, which
increased due to our growing portfolio. Our revenue for the period ended
September 30, 2001, includes the consolidated results of additional
facilities that we acquired or completed construction on subsequent to
September 30, 2000. Our power marketing revenue (sales of purchased power)
grew by $1,972.8 million due to increased price hedging and optimization
activity as a result of the growth of our subsidiary, Calpine Energy
Services, LP ("CES"), and our operating plant portfolio during the three
months ended September 30, 2001. We also recognized $13.6 million in mark
to market gains on power derivatives. This gain resulted from entering into
an undesignated derivative contract in a market area where we do not have
generating assets and therefore the contract was neither a hedge nor a
normal purchase or sale. Our expansion plans may result in our entry into
new markets within the next few years, which could present similar
opportunities, and any resulting power and gas contracts will require
similar accounting treatment.
Oil and gas production and marketing revenue increased to $139.4 million in
2001 compared to $92.9 million in 2000. The increase is due to a $46.9
million increase in marketing activities relating to purchased gas sold to
third parties in hedging, balancing and related transactions.
Other revenue increased to $14.3 million in 2001 compared to $1.0 million
in 2000. This increase is due primarily to $4.0 million recognized in 2001
from our custom turbine parts manufacturing subsidiary, Power Systems Mfg.,
LLC ("PSM"), which was acquired in December 2000, $2.6 million in interest
income on loans to power projects, and $4.6 million in commissioning
services related to our Delta Energy Center ("Delta") joint venture.
Cost of revenue -- Cost of revenue increased to $2,380.2 million in 2001
compared to $418.6 million in 2000. Approximately $1,710.5 million of the
$1,961.6 million increase relates to the cost of power purchased by our energy
services organization. Similarly, oil and gas production and marketing expense
grew by $41.1 million, largely due to $52.9 million of expense for the cost of
gas purchased by our energy services organization, compared to $9.4 million in
the third quarter of 2000, this was offset by a $2.4 million decrease in oil and
gas production expense. Fuel expense increased 74%, from $185.6 million in 2000
to $322.1 million in 2001, due to a 94% increase in megawatt hours generated and
increased fuel prices. Depreciation expense increased by 55%, from $59.1 million
in the third quarter of 2000 to $91.5 million in the third quarter of 2001, due
to additional power facilities in consolidated operations at September 30, 2001
as compared to the same period in 2000, and due to $10.4 million in higher
depreciation and depletion in our oil and gas operating subsidiaries.
Project development expense -- Project development expense decreased 20% due to
several projects moving from early to late stage development during the three
months ended September 30, 2001.
General and administrative expense -- General and administrative expense
increased 6% to $29.9 million for the three months ended September 30, 2001, as
compared to $28.1 million for the same period in 2000. The increase was
attributable to continued growth in personnel and associated overhead costs
necessary to support the overall growth in our operations and due to recent
acquisitions, including power facilities and natural gas operations. This was
offset by a decrease in cash bonus accruals to reflect a higher mix of stock
options in the Company's incentive program for management.
Interest expense -- Interest expense increased 71% to $49.7 million for the
three months ended September 30, 2001, from $29.1 million for the same period in
2000. Interest expense increased primarily due to the issuances of $250.0
million of Senior Notes Due 2005 in August 2000, $750.0 million of Senior Notes
Due 2010 in August 2000, $1.15 billion of Senior Notes Due 2011 in February
26
2001 and $1.5 billion of Calpine Canada Energy Finance ULC Senior Notes Due 2008
in April 2001. The associated incremental interest expense was partially offset
by interest capitalized in connection with our growing construction portfolio.
Distributions on trust preferred securities -- Distributions on trust preferred
securities increased 21% to $15.4 million for the three months ended September
30, 2001, compared to $12.7 million for the corresponding months in 2000. The
increase is attributable to a full period of distributions in 2001 on the August
2000 offering.
Interest income -- Interest income increased to $21.1 million for the three
months ended September 30, 2001, compared to $15.9 million for the same period
in 2000. This increase is due to interest income on the PG&E receivable.
Other income (expense) -- Other income (expense) increased to $7.9 million in
2001 from $(1.2) million in 2000 primarily due to contingent income as the
result of the sale of the Bayonne Power Plant and a gain on the sale of the
Cessford property in Canada.
Provision for income taxes -- The effective income tax rate was approximately
31.0% and 40.2% for the three months ended September 30, 2001 and 2000,
respectively. The decrease in rates was due to a year to date true-up in
accordance with APB Opinion No. 28 to reflect our expansion into Canada and the
United Kingdom and our cross border financings, which reduced our statutory tax
rates.
Extraordinary charge, net -- The $1.2 million charge in 2000 represents the
write-off of deferred financing costs related to the repayment of bridge
financing and the Bank One, Texas, N.A. borrowing base facilities.
Nine Months Ended September 30, 2001, Compared to Nine Months Ended September
30, 2000
Revenue -- Total revenue increased to $5,868.7 million for the nine months ended
September 30, 2001, compared to $1,447.2 million for the same period in 2000.
Electric generation and marketing revenue increased to $5,063.0 million in
2001 compared to $1,191.5 million in 2000. Approximately $719.8 million of
the $3,871.5 million variance was due to electricity and steam sales, which
increased due to our growing portfolio and favorable energy pricing. Our
revenue for the period ended September 30, 2001, includes the consolidated
results of additional facilities that we acquired or completed construction
on subsequent to September 30, 2000. Our power marketing activities
contributed an additional $3,068.4 million due to increased price hedging
and optimization activity as a result of the growth of CES and our
operating plant portfolio during the nine months ended September 30, 2001.
We also recognized $83.3 million in mark to market gains on power
derivatives. Almost all of this gain resulted from entering into
undesignated derivative contracts where we do not have generating assets
and therefore such contracts were neither hedges nor normal purchases or
sales. The majority of the gain ($68.5 million) was recognized in the
second quarter of 2001 from entering into a fixed-price firm-quantity power
sales contract for 2002 - 2006 with one counterparty in a market area where
we will not have generating assets for at least the first six months of the
contract. The contract presented us with an opportunity to establish a
commercial relationship with an important customer in a market where we
will eventually have generation assets, and we determined there was
substantial benefit in executing the agreement for the entire term
requested by the counterparty as opportunities to enter into such contract
may be available infrequently. Because of the structure of the contract,
under SFAS No. 133 the contract and the related commodity derivative
transactions did not constitute a hedge or a normal purchase or sale.
Before taking into account time value of money considerations, the
aggregate gain was $79.9 million. At September 30, 2001, this gain was
locked in as a result of entering into offsetting fixed-price power
purchases. However, on December 10, 2001, we terminated the portion of
those offsetting purchases where Enron was the counterparty, which
constituted approximately 30% of the power purchases. We are currently in
the process of replacing these contracts, and accordingly during this
period, we are exposed to changes in prices. Prior to December 31, 2001, we
realized a gain of approximately $1.4 million on a pretax basis in
connection with this exposure. At December 31, 2001, we had replaced
approximately 19% of liquidated volume.
Oil and gas production and marketing revenue increased to $768.3 million in
2001 compared to $229.5 million in 2000. Approximately $386.5 million of
the increase is due to marketing activities relating to purchased gas sold
to third parties in hedging, balancing and related transactions.
Additionally, approximately $152.3 million of the variance relates to
increased production and commodity prices in sales to third parties from
reserves acquired in Canada and the United States.
Income from unconsolidated investments in power projects decreased to $9.0
million in 2001 compared to $21.8 million during 2000. The variance is
primarily due to the contractual reduction in distributions from the Sumas
Power Plant of approximately $12.3 million.
27
Other revenue increased to $28.4 million in 2001 compared to $4.4 million
in 2000. This increase is due primarily to $10.4 million recognized in 2001
from PSM, $5.9 million in commissioning services related to Delta and a
$5.4 million increase in interest income on loans to power projects.
Cost of revenue -- Cost of revenue increased to $4,753.0 million in 2001
compared to $903.1 million in 2000. Approximately $2,779.2 million of the
$3,849.9 million increase relates to the cost of power purchased by our energy
services organization. Similarly, oil and gas production and marketing expense
grew by $384.1 million, largely due to a $365.2 million increase in expense for
the cost of gas purchased and resold by our energy services organization. Fuel
expense increased 122%, from $363.3 million in 2000 to $807.5 million in 2001,
due to a 79% increase in megawatt hours generated and a significant increase in
fuel price. Depreciation expense increased by 52%, from $154.9 million in the
first nine months of 2000 to $235.7 million in the first nine months of 2001,
due to additional power facilities in operation in 2001 and due to $40.6 million
in higher depreciation and depletion in our oil and gas operating subsidiaries.
Operating lease expense increased by $36.9 million due to leases entered into or
acquired in connection with our Pasadena, Tiverton, Rumford, KIAC, West Ford
Flat and Bear Canyon facilities during and subsequent to the period ended
September 30, 2000.
Project development expense -- Project development expense increased 67% due to
an increase of projects in the early stage of development.
General and administrative expense -- General and administrative expense
increased 103% to $116.5 million for the nine months ended September 30, 2001,
as compared to $57.3 million for the same period in 2000. The increase was
attributable to continued growth in personnel and associated overhead costs
necessary to support the overall growth in our operations and due to recent
acquisitions, including power facilities and natural gas operations. This
increase was offset by a decrease in cash bonus accruals to reflect a higher mix
of stock options in the Company's incentive program for management.
Merger Expense -- We incurred approximately $41.6 million of expense in the nine
months ended September 30, 2001, in connection with the merger with Encal Energy
Ltd. on April 19, 2001. The transaction was accounted for under the
pooling-of-interests method and, accordingly, all transaction costs have been
expensed as incurred and all periods presented have been restated to reflect the
transaction.
Interest expense -- Interest expense increased 64% to $113.0 million for the
nine months ended September 30, 2001, from $69.0 million for the same period in
2000. Interest expense increased primarily due to the issuances of $250.0
million of Senior Notes Due 2005 in August 2000, $750.0 million of Senior Notes
Due 2010 in August 2000, $1.15 billion of Senior Notes Due 2011 in February 2001
and $1.5 billion of Energy Finance Senior Notes Due 2008 in April 2000. The
associated incremental interest expense was partially offset by interest
capitalized in connection with our growing construction portfolio.
Distributions on trust preferred securities -- Distributions on trust preferred
securities increased 60% to $45.9 million for the first nine months in 2001
compared to $28.7 million for the corresponding months in 2000. The increase is
attributable to the issuance of additional trust preferred securities in August
2000, as well as a full period of distributions in 2001 on the January 2000
offering and the subsequent exercise of the initial purchasers' option to
purchase additional securities.
Interest income -- Interest income increased to $61.0 million for the nine
months ended September 30, 2001, compared to $29.1 million for the same period
in 2000. This increase is due primarily to the significantly higher cash
balances that we have maintained as a result of our senior notes and convertible
securities offerings during the first and second quarters of 2001. This increase
is also due to interest income on the PG&E receivable.
Other income (expense) -- Other income (expense) increased to $16.9 million in
2001 from $(1.4) million in 2000 primarily due to a gain on the sale of our
interests in the Elwood development project, the Cessford property in Canada and
the Bayonne Power Plant including related contingent income recognized as earned
thereafter.
Provision for income taxes -- The effective income tax rate was approximately
35.6% and 40.4% for the nine months ended September 30, 2001 and 2000,
respectively. The decrease in rates was due to a year to date true-up in
accordance with APB Opinion No. 28 to reflect our expansion into Canada and the
United Kingdom and our cross border financings, which reduced our statutory tax
rates.
28
Extraordinary charge, net -- The $1.3 million charge in 2001 was a result of
writing off unamortized deferred financing costs related to the repayment of
$105.0 million 9 1/4% Senior Notes Due 2004. The $1.2 million charge in 2000
represents the write-off of deferred financing costs related to the repayment of
bridge financing and the Bank One, Texas, N.A. borrowing base facilities.
Cumulative effect of a change in accounting principle -- The $1.0 million of
additional income, net of tax, is due to the adoption in 2001 of Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities," amended by SFAS No. 137 and SFAS No. 138
("SFAS No. 133").
Selected Balance Sheet Information
Unconsolidated Investments in Power Projects -- Although our preference is to
own 100% of the power plants we acquire or develop, there are situations when we
take less than 100% ownership. Reasons why we may take less than a 100% interest
in a power plant may include, but are not limited to: (a) our acquisitions of
other IPP's such as Cogeneration Corporation of America in 1999 and SkyGen
Energy LLC in 2000 in which minority interest projects were included in the
portfolio of assets owned by the acquired entities (Grays Ferry Power Plant (40%
now owned by Calpine) and Androscoggin Energy Center (32.3% now owned by
Calpine) respectively); (b) opportunities to co-invest with non-regulated
subsidiaries of regulated electric utilities, which under the Public Utility
Regulatory Policies Act of 1978, as amended are restricted to 50% ownership of
cogeneration qualifying facilities -- such as our investment in Gordonsville
Power Plant (50% owned by Calpine and 50% owned by Edison Mission Energy, which
is wholly-owned by Edison International Company); and (c) opportunities to
invest in merchant power projects with partners who bring marketing, funding,
permitting or other resources that add value to a project. An example of this is
Acadia Energy Center, which is under construction in Louisiana (50% owned by
Calpine and 50% owned by Cleco Midstream Resources, an affiliate of Cleco
Corporation). None of our equity investment projects have nominal carrying
values as a result of material recurring losses. Further, there is no history of
impairment in any of these investments.
Accumulated other comprehensive loss -- Accumulated other comprehensive loss at
September 30, 2001 was $223.2 million. This represents the sum of our unrealized
Other Comprehensive Income ("OCI") activity for the nine month period ending
September 30, 2001 of $200.1 million and the ending OCI balance at December 31,
2000 of $23.1 million.
Accumulated other comprehensive loss includes the following components: (i)
unrealized pre-tax gains/losses, net of reclassification-to-earnings
adjustments, from effective cash flow hedges as designated pursuant to SFAS 133
(See Note 8 - "Derivative Instruments" in the Notes to the Consolidated
Condensed Financial Statements included herein); (ii) unrealized pre-tax
gains/losses that result from the translation of foreign subsidiaries' balance
sheets from the foreign functional currency (primarily Cdn.$) to our
consolidated reporting currency (U.S.$); and (iii) the taxes associated with the
unrealized gains/losses from items (i) and (ii). See Note 9 - "Comprehensive
Income" in the Notes to the Consolidated Condensed Financial Statements included
herein for further information.
Liquidity and Capital Resources
General -- To date, we have obtained cash from our operations; borrowings under
our credit facilities and other working capital lines; sales of debt, equity,
trust preferred securities and convertible debentures; operating leases,
including from sale-leaseback transactions and proceeds from project financing.
We have utilized this cash to fund our operations, service debt obligations,
fund acquisitions, develop and construct power generation facilities, finance
capital expenditures and meet our other cash and liquidity needs.
Our business is capital intensive. We are dependent on the availability of
capital on attractive terms. Our strategy is also to reinvest our cash from
operations into our business development and construction program.
Following a comprehensive review of our power plant development program, we
recently announced the adoption of a revised capital expenditure program, which
contemplates the completion of 27 power projects (representing 15,200 MW)
currently under construction during 2002 and 2003. Construction of an additional
34 advanced-stage development projects (representing 15,100 MW) will be placed
on hold following completion of advanced development activities pending further
review, reducing previously forecasted 2002 capital spending by as much as $2
billion. Construction of these advanced stage development projects is expected
to proceed when there is an established marked need for additional generating
resources at prices that will allow us to meet our established investment
criteria, and when capital is available to us on attractive terms. However, our
development and construction program is flexible and subject to continuing
review and revision based upon such criteria.
29
Notwithstanding recent uncertainties in the domestic energy and capital markets,
we have raised substantial capital. In the last quarter of 2001 and early 2002,
we have raised nearly $5 billion of capital, including $2.6 billion in
sale/leaseback transactions and senior notes issued in the U.S., Canada, the
U.K. and other European markets (representing an increase in size from the $2.0
billion that we had initially sought to raise), $1.2 billion in convertible
senior notes in a private placement in the U.S. (representing an increase in
size from the $500 million that we had initially sought to raise), and an
additional $1 billion unsecured working capital credit facility, which was
recently announced and is expected to close in the first quarter of 2002.
We believe the following factors are important in assessing our ability to
continue to fund our growth in the capital markets: (a) our debt-to-capital
ratio; (b) various interest coverage ratios; (c) our credit and debt ratings by
the rating agencies; (d) the trading prices of our senior notes in the capital
markets; (e) the price of our common stock on the New York Stock Exchange; (f)
our anticipated capital requirements over the coming quarters and years; (g) the
profitability of our operations; (h) our cash balances and remaining capacity
under existing revolving credit construction and general purpose facilities; (i)
compliance with covenants in existing debt facilities; (j) actual progress in
raising new or replacement capital; and (k) the stability of future contractual
cash flows. We believe that our ability to complete the financing transactions
described above in difficult conditions affecting the market, and our sector, in
general demonstrate our ability to have access to the capital markets in the
future, although availability of capital has tightened significantly throughout
the power generation industry in the first quarter of 2002.
Negative working capital at September 30, 2001 -- At September 30, 2001, we had
$873 million of negative working capital. The primary reasons for this were: (a)
classification of the $1 billion in aggregate principal amount of our
Zero-Coupon Convertible Debentures due 2021 ("Zero Coupons") as a current
liability due to the one year put feature contained in these securities (this
put is exercisable on April 30, 2002 and, based on the low price of our common
stock compared to the conversion price, we concluded at that time that exercise
of the put was highly probable); and (b) reclassification of $265.6 million in
pre-bankruptcy petition PG&E receivables to non-current assets from current
assets because of the assessment at that time that it was not likely that we
would recover those receivables from PG&E within one year.
From December 2001 through February 2002 we repurchased $314.5 million in
aggregate principal of the Zero Coupons in the market. We also issued in
separate closings in December 2001 and January 2002 $1.2 billion in aggregate
principal amount of Convertible Senior Notes due 2006. Proceeds from this
offering will be used to retire the Zero Coupons that remain outstanding, either
in open-market purchases, negotiated transactions or upon exercise by holders of
the April 2002 put option described above. In December 2001, the bankruptcy
court approved an agreement between Calpine and PG&E whereby PG&E will repay the
$265.6 million in past due pre-petition receivables plus accrued interest
thereon beginning on December 31, 2001 and with monthly payments thereafter over
the next 11 months. Shortly following receipt of this bankruptcy court approval
and the first payments from PG&E on December 31, 2001, we sold the remaining
PG&E receivables to a third party at a $9.0 million discount. These subsequent
events are expected to return our working capital at December 31, 2001 to a
positive amount.
Letter of credit facility -- In August 2001, we entered into a $300 million
Master Reimbursement Agreement for Letters of Credit with Credit Suisse First
Boston. This facility, which was used to provide credit support to CES in
connection with its trading operations, expired pursuant to its terms on
December 31, 2001, and we replaced the credit support that it had provided with
direct cash deposits. Inclusive of this facility, we had approximately $730.8
million in letters of credit outstanding under various credit support
facilities, of which $393.5 million related to CES risk management activities.
The remainder related to other operational and construction activities.
CES margin deposits -- As of September 30, 2001, CES had deposited $173.3
million in cash as margin deposits with third parties related to its business
activities.
Outlook
Our strategy is to continue our rapid growth by capitalizing on the significant
opportunities in the power industry, primarily through our active development
and acquisition programs. In pursuing our proven growth strategy, we utilize our
extensive management and technical expertise to implement a fully integrated
approach to the acquisition, development and operation of power generation
facilities. This approach combines our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations, risk management and power marketing, to provide us with a
competitive advantage. The key elements of our strategy are as follows:
Development of new and expansion of existing power plants -- We are actively
pursuing the development of new and expansion of both baseload and peaking
capacity at our existing highly efficient, low-cost, gas-fired power plants that
replace old and inefficient generating facilities and meet the demand for new
generation. Our strategy is to develop power plants in strategic geographic
locations that enable us to leverage existing power generation assets and
operate the power plants as integrated electric generation systems. This
30
allows us to achieve significant operating synergies and efficiencies in fuel
procurement, power marketing and operation and maintenance.
At November 12, 2001, we had 30 projects under construction, representing an
additional 17,065 megawatts of net capacity. Included in these 30 projects are 4
project expansions, representing 734 megawatts of net capacity. We have also
announced plans to develop 31 additional power generation projects, representing
a net capacity of 17,569 megawatts. Included in these 31 development projects
are 6 expansion projects representing 592 megawatts.
Acquisition of power plants -- Our strategy is to acquire power generating
facilities that meet our stringent acquisition criteria and provide significant
potential for revenue, cash flow and earnings growth, and that provide the
opportunity to enhance the operating efficiencies of the plants. We have
significantly expanded and diversified our project portfolio through numerous
acquisitions of power generation facilities.
Enhance the performance and efficiency of existing power projects -- We
continually seek to maximize the power generation potential of our operating
assets and minimize our operation and maintenance expense and fuel cost. This
will become even more significant as our portfolio of power generation
facilities expands to 87 power plants with a net capacity of 28,150 megawatts,
after completion of our projects currently under construction. We focus on
operating our plants as an integrated system of power generation, which enables
us to minimize costs and maximize operating efficiencies. We believe that
achieving and maintaining a low cost of production will be increasingly
important to compete effectively in the power generation industry.
Overview
The Company is engaged in the development, acquisition, ownership, and operation
of power generation facilities and the sale of electricity and steam in the
United States, Canada and the United Kingdom. At November 12, 2001, we had
interests in 61 operating power plants representing 11,085 megawatts of net
capacity.
ACQUISITIONS
DATE DESCRIPTION SELLER PRICE
- ---- ----------- ------ -----
8/1/01 Announced agreement to purchase remaining 50% Edison Mission Energy $35 million
equity interest in Gordonsville Power Plant
8/15/01 Acquired 86% of the voting stock of Michael Shareholders of Michael $273.6 million and
Petroleum Corporation Petroleum Corporation assumption of
$54.5 million of debt
8/24/01 Acquired the 1,200-megawatt Saltend Energy Centre Entergy Corporation US$814.4 million
(at exchange rates at the
closing of the acquisition)
9/12/01 Acquired remaining 33.3% interests in Hog Bayou Intergen $9.6 million
and Pine Bluff Energy Centers (North America), Inc.
9/20/01 Acquired 100% interest in the 250-megawatt Island Westcoast Energy Inc. US$212.1 million
Cogeneration facility and 50% interest in the (at exchange rates at the
50-megawatt Whitby Cogeneration facility closing of the acquisition)
10/16/01 Acquired California Energy General Corporation MidAmerican Energy undisclosed amount
and CE Newburry, Inc. Holdings Company
10/22/01 Acquired the remaining 14% of the voting stock Shareholders of Michael $41.9 million
of Michael Petroleum Corporation Petroleum Corporation
11/5/01 Acquired Highland Energy Company Entergy Power Gas undisclosed amount
Operations Corporation
and Louis Morrison III
11/6/01 Acquired remaining 50% interest in Delta Bechtel Enterprises Approximately
Energy Center, Metcalf Energy Center and Holdings, Inc. $154 million and the
Russell City Energy Center assumption of approximately
$141 million of debt
31
FINANCE
Offerings of Senior Notes:
DATE OFFERING RATE DUE ISSUER
- ---- -------- ---- --- ------
10/16/01 US $530 million 8.500% 2008 Calpine Canada Energy Finance ULC
10/16/01 US $850 million 8.500% 2011 Calpine Corporation
10/18/01 C$200 million 8.750% 2007 Calpine Canada Energy Finance ULC
10/18/01 L200 million 8.875% 2011 Calpine Canada Energy Finance II ULC
10/18/01 E175 million 8.375% 2008 Calpine Canada Energy Finance II ULC
Sale/Leaseback Transactions:
DATE PROCEEDS FACILITY
- ---- -------- --------
10/18/01 $800.0 million South Point Energy Center, Broad River
Energy Center and RockGen Energy Center
Other:
DATE DESCRIPTION
- ---- -----------
9/28/01 Announced the amendment of certain provisions of the Stockholder Rights Agreement
10/2/01 Moody's Investors Service upgraded corporate credit and senior unsecured notes of Calpine to Baa3 from Ba1
12/14/01 Moody's Investors Service downgraded corporate credit and senior unsecured notes of Calpine to Ba1 from
Baa3
12/19/01 Fitch downgraded senior unsecured debt rating of Calpine to BB+
POWER PLANT DEVELOPMENT AND CONSTRUCTION
DATE PROJECT DESCRIPTION
- ---- ------- -----------
7/2/01 Sutter Energy Center Announced commercial operation
7/9/01 Los Medanos Energy Center Announced initial operation
7/10/01 500-megawatt Otay Mesa Generating Project located in San Acquired from the PG&E National Energy Group
Diego County, California
7/11/01 600-megawatt Russell City Energy Center located in Hayward, Application for Certification ("AFC") met the
California California Energy Commission's ("CEC")
data adequacy requirements; approved for
expedited review
7/11/01 180-megawatt Los Esteros Critical Energy Facility located in Announced plans for development
San Jose, California
7/11/01 Hog Bayou Energy Center Announced commercial operation
7/16/01 Aries Power Project Announced simple-cycle operation
7/17/01 900-megawatt Sherry Energy Center located in Wood County, Announced plans for development
Wisconsin
7/30/01 Channel Energy Center Announced simple-cycle operation
8/24/01 540-megawatt Wawayanda Energy center located in the town of Announced filing of Article X Application
Wawayanda, New York
9/5/01 Broad River Energy Center Announced commercial operation of 350-megawatt
expansion
9/24/01 Pine Bluff Energy Center Announced commercial operation
9/24/01 Metcalf Energy Center CEC voted unanimously to approve the
construction and operation
10/16/01 49.5-megawatt Fourmile Hill Geothermal Project in the Glass Announced plans for development
Mountain Known Geothermal Resource Area in California
11/1/01 905-megawatt Palmetto Energy Center located in South Carolina Announced plans for development
11/1/01 1,100-megawatt Central Valley Energy Center located in Announced filing of AFC with the CEC
San Joaquin, California
TURBINE PURCHASES
32
DATE OF ANNOUNCEMENT TURBINES MANUFACTURER DELIVERY DATES
- -------------------- -------- ------------ --------------
8/9/01 27 steam turbines Siemens Westinghouse 2002 through 2005
8/22/01 19 steam turbines Toshiba International Corporation 2002 through 2005
MANAGEMENT DEVELOPMENTS
DATE OF ANNOUNCEMENT INDIVIDUAL DESCRIPTION
- -------------------- ---------- -----------
7/16/01 Michael Polsky Resignation from the Board of Directors and as an officer of the
Company
7/17/01 Gerald Greenwald Appointment to the Board of Directors
11/5/01 David Johnson Resignation as President and Chief Executive Officer of Calpine
Canada
In accordance with SFAS No. 13 and SFAS No. 98, "Accounting for Leases" the
Company's operating leases are not reflected on our balance sheet. Similarly, in
accordance with APB Opinion No. 18 "The Equity Method of Accounting For
Investments in Common Stock" and FASB Interpretation No. 35, "Criteria for
Applying the Equity Method of Accounting for Investments in Common Stock (An
Interpretation of APB Opinion No. 18)", the debt on the books of our
unconsolidated equity investments is not reflected on our balance sheet. The
investee debt is part of the total investee liabilities disclosed in the 2000
10-K in Note 6. The investee debt is currently estimated to be approximately
$600 million. Based on our pro rata ownership share of each of the investments,
our share is approximately $200 million.
We have not incurred any off-balance sheet financings since September 30, 2001
other than sale/leaseback transactions entered into in October 2001. All equity
investors in these transactions are third parties that are unrelated to Calpine.
The equity investees in such transactions are unrelated to Calpine and are often
special-purpose entities formed by the equity investors with the sole purpose of
owning a power generation facility. All equity investee debt referred to above
is non-recourse to Calpine except in the case of the Aries construction debt,
for which the partners, Calpine Corporation and Aquila Energy, a wholly owned
subsidiary of UtiliCorp United, have provided equity support arrangements until
construction is completed to cover cost overruns, if any. Calpine makes rent
payments to the equity investees under these arrangements.
Enron Corp. -- On November 14, 2001, CES entered into a master netting agreement
with certain Enron affiliates. On December 2, 2001, Enron Corp. and certain of
its subsidiaries filed voluntary petitions for Chapter 11 reorganization with
the U.S. Bankruptcy Court for the Southern District of New York. See Note 11 -
"Significant Customers" in the Notes to Consolidated Condensed Financial
Statements herein for further discussion of our exposure to Enron and its
subsidiaries.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3%
and $1,329.8 million or 22.7%, of our revenue was with Enron subsidiaries,
primarily Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp.
("ENA"). We, primarily our subsidiary, CES, purchases significant amounts of
fuel and power from ENA and EPMI, giving rise to current accounts payable and
open contract fair value positions. For the three months ended September 30,
2001, CES had fuel and power purchases from ENA and EPMI of $905.3 million. For
the nine months ended September 30, 2001, CES had fuel and power purchases from
ENA and EPMI of $1,358.7 million. These purchases must be included in an overall
understanding of our Enron exposure. The sales to and purchases from various
Enron subsidiaries are mostly hedging, balancing and related and optimization
transactions, and in most cases the purchases and sales are not related and
should not be netted to try to gauge the profitability of transactions with
Enron subsidiaries.
ENA is the parent corporation of EPMI. Enron is the direct or indirect parent
corporation of ENA. In assessing our exposure to Enron subsidiaries and
affiliates, we analyze our accounts receivable and accounts payable balances on
contracts that have already settled and also the fair value (mark to market
value) of the contracts that have not settled. In the event of a default by one
or more of the Enron subsidiaries and affiliates, we might terminate some or all
of the open contracts, in which case we would have an exposure to realize the
fair value of the positive ("in the money") contracts. In managing the overall
credit exposure to each other, Calpine and Enron have entered into a netting
agreement in which they net or offset overall mark to market exposures from all
transactions between certain Enron subsidiaries and CES to liabilities between
those entities.
See Footnote 11 for our accounts receivable (payable) balances as well as the
fair value of our open contracts with Enron subsidiaries and affiliates at
November 29, 2001. We have one gas contract with Citrus Trading Corporation to
purchase gas from Citrus. Our credit department has had conversations with El
Paso in which El Paso affirmed their commitment to continue all deliveries of
gas to Citrus. As further assurance, El Paso also stated that they have the
first option to purchase the remaining 50% of Citrus Trading Corporation from
Enron in the event Enron chooses to sell their share of Citrus Trading
Corporation. Currently, Citrus has continued to deliver all gas as required
under the contract. Our Auburndale entity is the beneficiary of a guarantee by
El Paso of 50% of Citrus' payment obligations under the Citrus fuel supply
contract with Auburndale.
33
Based upon the foregoing, the Company has determined that a loss due to any
credit exposure to Enron and its affiliates is not probable and therefore has
not established a reserve relating thereto.
Our treasury department includes a credit group focused on monitoring and
managing counterparty risk. The credit group monitors the net exposure with each
counterparty on a daily basis. The analysis is performed on a mark to market
basis using the forward curves audited by our Risk Controls group. The net
exposure is compared against a counterparty credit risk threshold which is
determined based on the counterparty's credit ratings, evaluation of the
financial statements and bond values. The credit department monitors these
thresholds to determine the need for additional collateral or an adjustment to
activity with the counterparty.
We will continue to evaluate the Enron risk in the same manner as discussed
above. We will adjust our threshold for Enron exposure based on factors
discussed above and continue to monitor the exposure on a daily basis.
We do not expect any material change in our earnings and operations if
Enron is unable to continue as a supplier and customer. Our transactions with
Enron were at market based pricing and we expect to continue to transact on
similar terms with other counterparties. The capital market response to Enron's
situation has impacted the entire industry's credit capacity to transact. It is
hard to assess the long term impact of this on earnings, but, as an asset based
company, we have the option and flexibility to increase our direct dealings
with load serving entities, if we experience a reduced primary demand for
electricity.
California Power Market -- The deregulation of the California power market has
produced significant unanticipated results in the past year and a half. The
deregulation froze the rates that utilities can charge their retail and business
customers in California, until recent rate increases approved by the California
Public Utilities Commission ("CPUC"), and prohibited the utilities from buying
power on a forward basis, while wholesale power prices were not subjected to
limits.
In the past year and a half, a series of factors have reduced the supply of
power to California, which has resulted in wholesale power prices that for a
period from mid 2000 to spring 2001 were significantly higher than historical
levels. Several factors contributed to this increase. These included:
- significantly increased volatility in prices and supplies of natural
gas;
- an unusually dry fall and winter in the Pacific Northwest during 2000,
which reduced the amount of available hydroelectric power from that
region (typically, California imports a portion of its power from this
source);
- the large number of power generating facilities in California nearing
the end of their useful lives, resulting in increased downtime (either
for repairs or because they have exhausted their air pollution credits
and replacement credits have become too costly to acquire on the
secondary market); and
- continued obstacles to new power plant construction in California, which
deprived the market of new power sources that could have, in part,
ameliorated the adverse effects of the foregoing factors.
As a result of this situation, two major California utilities that were subject
to the retail rate freeze, including PG&E, have faced wholesale prices that far
exceeded the retail prices they were permitted to charge. This led to
significant under-recovery of costs by these utilities. As a consequence, these
utilities defaulted under a variety of contractual obligations, including
payment obligations to power generators. PG&E has defaulted on payment
obligations to the Company under its long-term QF contracts, which are subject
to federal regulation under the Public Utility Regulatory Policies Act of 1978,
as amended ("PURPA"). The PG&E QF contracts are in place at eleven of our
facilities and represent nearly 600 megawatts of electricity for Northern
California customers.
PG&E Bankruptcy Proceedings -- On April 6, 2001, PG&E filed for bankruptcy
protection under Chapter 11 of the United States Bankruptcy Code. As of April 6,
2001, we had recorded approximately $265.6 million in accounts receivable with
PG&E under our QF contracts, plus $68.7 million in notes receivable not yet due
and payable. As of September 30, 2001, we had recorded $292.1 million in
accounts receivable (the pre-petition amount of $265.6 and associated $6.0
million in interest income are classified as a long-term receivable) and $105.6
million in notes receivable not yet due and payable. We are currently selling
power to PG&E pursuant to our long-term QF contracts, and PG&E is paying on a
current basis for these purchases since its bankruptcy filing. With respect to
the receivables recorded under these contracts, we announced on July 6, 2001,
that we had entered into a binding agreement with PG&E to modify all of our QF
contracts with PG&E and that, based upon such modification, PG&E had agreed to
assume all of the QF contracts. Under the terms of this agreement, we will
continue to receive our contractual capacity payments under the QF contracts,
plus a five-year fixed energy price component that averages 5.37 cents per
kilowatt-hour in lieu of the short run avoided cost. In addition, all past due
receivables under the QF contracts will be elevated to administrative priority
status in the PG&E bankruptcy proceeding and will be paid to the Company, with
interest, upon the effective date of a confirmed plan of reorganization.
Administrative claims enjoy priority over payments made to the general unsecured
creditors in bankruptcy. The bankruptcy court approved the agreement on July 12,
2001. On September 20, 2001, PG&E filed its proposed plan of reorganization with
the bankruptcy court. This plan is consistent with the agreement between the
Company and PG&E described above. We cannot predict
34
when the bankruptcy court will confirm a plan of reorganization for PG&E, but
anticipate that it will be at least twelve months following September 30, 2001.
CPUC Proceedings Regarding QF Contract Pricing -- Our QF contracts with PG&E
provide that the CPUC has the authority to determine the appropriate utility
"avoided cost" to be used to set energy payments for certain QF contracts,
including those for all of our QF plants in California which sell power to PG&E.
Section 390 of the California Public Utility Code provides QFs the option to
elect to receive energy payments based on the California Power Exchange ("PX")
market clearing price. In mid-2000, our QF facilities elected this option and
were paid based upon the PX zonal day ahead clearing price ("PX Price") from
summer 2000 until January 19, 2001, when the PX ceased operating a day ahead
market. Since that time, the CPUC has ordered that the price to be paid for
energy deliveries by QFs electing the PX Price shall be based on a natural gas
cost-based "transition formula." The CPUC has conducted proceedings
(R.99-11-022) to determine whether the PX Price was the appropriate price for
the energy component upon which to base payments to QFs which had elected the
PX-based pricing option. The CPUC has issued a proposed decision to the effect
that the PX price was the appropriate price for energy payments under the
California Public Utility Code. However, a final decision has not been issued to
date. Therefore, it is possible that the CPUC could order a payment adjustment
based on a different energy price determination. We believe that the PX Price
was the appropriate price for energy payments but there can be no assurance that
this will be the outcome of the CPUC proceedings.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March
2001 Decision") proposing to change, on a prospective basis, the composition of
the short run avoided cost ("SRAC") energy price formula, which is reset
monthly, used by the California utilities in QF contracts. Prior to the March
2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50%
Malin border gas indices. In the March 2001 Decision, the CPUC changed this
formulation to eliminate the prices at Topock from the SRAC formula. The March
2001 Decision is subject to challenges at the CPUC and the Federal Energy
Regulatory Commission ("FERC").
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the
"June 2001 Decision") that authorized the California utilities, including PG&E,
to amend QF contracts to elect a fixed energy price component that averages 5.37
cents per kilowatt-hour for a five-year term under those contracts in lieu of
using the SRAC energy price formula. By this order, the CPUC authorized the QF
contract energy price amendments without further CPUC concurrence. As part of
the agreement we entered into with PG&E pursuant to which PG&E, in bankruptcy,
agreed to assume its QF contracts with us, PG&E agreed with us to amend these
contracts to adopt the fixed price component, that averages 5.37 cents pursuant
to the June 2001 Decision. This election became effective as of July 16, 2001.
As a result of the June 2001 Decision and our agreement with PG&E to amend the
QF contracts to adopt the fixed price energy component, the energy price
component in our QF contracts is now fixed for five years and we are no longer
subject to any uncertainty that may have existed with respect to this component
of our QF contract pricing as a result of the March 2001 Decision. Further, the
March 2001 Decision has no bearing on PG&E's agreement with us to assume the QF
contracts in bankruptcy or on the amount of the receivable that was so assumed.
As such, we have not reserved our PG&E receivables.
California Long-Term Supply Contracts -- California has adopted legislation
permitting it to issue long-term revenue bonds to provide funding for wholesale
purchases of power. The bonds will be repaid with the proceeds of payments by
retail customers over time. The California Department of Water Resources ("DWR")
sought bids for long-term power supply contracts in a publicly announced
auction. Calpine successfully bid in that auction and signed several long-term
power supply contracts with DWR.
On February 7, 2001, we announced the signing of a 10-year, $4.6 billion
fixed-price contract with DWR to provide electricity to the State of California.
We committed to sell up to 1,000 megawatts of electricity, with initial
deliveries of 200 megawatts starting October 1, 2001, which increases to 1,000
megawatts by January 1, 2004. The electricity will be sold directly to DWR on a
24 hours-a-day, 7 days-a-week basis.
On February 28, 2001, we announced the signing of two long-term power sales
contracts with DWR. Under the terms of the first contract, a 10-year, $5.2
billion fixed-price contract, we committed to sell up to 1,000 megawatts of
generation. Initial deliveries began July 1, 2001, with 200 megawatts and
increase to 1,000 megawatts by as early as July 2002. Under the terms of the
second contract, a 20-year contract totaling up to $3.1 billion, we will supply
DWR with up to 495 megawatts of peaking generation, beginning with 90 megawatts
as early as August 2001, and increasing up to 495 megawatts as early as August
2002.
FERC Investigation into California Wholesale Markets -- On June 19, 2001, FERC
ordered price mitigation in 11 states in the western United States in an attempt
to reduce the dependence of the California market on spot markets in favor of
longer-term committed energy supplies. The order provides for price mitigation
in the spot market throughout the 11 state western region during "reserve
deficiency hours," which is when operating reserves in California fall below
seven percent. This price will be a single market
35
clearing price based upon the marginal operating cost of the last unit
dispatched by the California ISO. In addition, FERC implemented price mitigation
in non-reserve deficiency hours, which will be set at 85% of the market clearing
price during the last reserve deficiency period. These price mitigation
procedures went into effect on June 20, 2001, and will remain in effect until
September 30, 2002.
The retention by FERC of a market-based, rather than a cost-of-service-based,
rate structure, will enable us to continue to realize benefits from our
efficient, modern power plants. We believe that Calpine's marginal costs will
continue to be below any price cap imposed by FERC, whether during reserve
deficiency hours or at other times. Therefore, we believe that FERC's mitigation
plan will not have a material adverse effect on Calpine's financial condition or
results of operations.
FERC also ordered all sellers and buyers in wholesale power markets administered
by the California ISO, as well as representatives of the State of California, to
participate in a settlement conference before a FERC administrative judge. The
settlement discussions were intended to resolve all issues that remain
outstanding to resolve past accounts, including sellers' claims for unpaid
invoices, and buyers' claims for refunds of alleged overcharges, for past
periods. The settlement discussions began on June 25, 2001, and ended on July 9,
2001. The Chief Administrative Law Judge issued his report and recommendations
to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited
fact-finding hearing to calculate refunds for spot market transactions in
California. The hearing has been delayed pending the submission by the
California ISO and the PX of data for the purpose of developing the factual
basis needed to implement the refund methodology and order refunds. The FERC
Administrative Law Judge presiding over this hearing recently announced that
this information must be submitted not later than December 7, 2001, and the
deadline for completion of the hearing is March 8, 2002. While it is not
possible to predict the amount of any refunds until the hearings take place,
based upon the information available at this time, we do not believe that this
proceeding will result in a material adverse effect on the Company's financial
condition or results of operations.
Risk Factors
Enron Corporation -- In 2001 the Company, primarily through our CES subsidiary,
has transacted a significant volume of business with units of Enron Corp.
("Enron"). Most of these transactions are contracts for sales and purchases of
power and gas for hedging and optimization purposes, some of which extend out as
far as 2009. In October and November of 2001, Enron announced a series of
developments including restatement of the last four years of earnings, an
investigation by the Securities and Exchange Commission relating to the adequacy
of Enron's disclosures of certain off-balance sheet financial transactions or
structures and dismissals of certain members of senior management. On December
2, 2001, Enron Corp. and certain of its subsidiaries filed voluntary petitions
for Chapter 11 reorganization with the U.S. Bankruptcy Court for the Southern
District of New York.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3%
and $1,329.8 million or 22.7% of our revenue was with Enron subsidiaries,
primarily Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp
("ENA"). We, primarily our subsidiary, CES, purchases significant amounts of
fuel and power from ENA and EPMI, giving rise to current accounts payable and
open contract fair value positions. For the three months ended September 30,
2001, CES had fuel and power purchases from ENA and EPMI of $905.3 million. For
the nine months ended September 30, 2001, CES had fuel and power purchases from
ENA and EPMI of $1,358.7 million. These purchases must be included in an overall
understanding of our Enron exposure. The sales to and purchases from various
Enron subsidiaries are mostly hedging and optimization transactions, and in most
cases the purchases and sales are not related and should not be netted to try to
gauge the profitability of transactions with Enron subsidiaries.
ENA is the parent corporation of EPMI. Enron is the direct or indirect parent
corporation of ENA. In assessing our exposure to Enron subsidiaries and
affiliates, we analyze our accounts receivable and accounts payable balances on
contracts that have already settled and also the fair value (mark to market
value) of the contracts that have not settled. In the event of a default by one
or more of the Enron subsidiaries and affiliates, we might terminate some or all
of the open contracts, in which case we would have an exposure to realize the
fair value of the positive ("in the money") contracts. In managing the overall
credit exposure to each other, Calpine and Enron have entered into a netting
agreement in which they net or offset overall mark to market exposures from all
transactions between certain Enron subsidiaries and CES to liabilities between
those entities.
See Footnote 11 for our accounts receivable (payable) balances as well as the
fair value of our open contracts with Enron subsidiaries and affiliates at
November 29, 2001. We had no net exposure at November 29, 2001. Additionally,
our Enron exposure is mitigated as we have open positions with Citrus Trading
Corp., which is 50% owned by El Paso Corporation. As such, a reserve is not
needed.
Our treasury department includes a credit group focused on monitoring and
managing counterparty risk. The credit group monitors the net exposure with each
counterparty on a daily basis. The analysis is performed on a mark to market
basis using the forward curves audited by our Risk Controls group. The net
exposure is compared against a counterparty credit risk threshold which is
determined based on the counterparty's credit ratings, evaluation of the
financial statements and bond values. The credit department monitors these
thresholds to determine the need for additional collateral or an adjustment to
activity with the counterparty.
We will continue to evaluate the Enron risk in the same manner as discussed
above. We will adjust our threshold for Enron exposure based on factors
discussed above and continue to monitor the exposure on a daily basis.
CPUC Proceedings Regarding QF Contract Pricing -- Our QF contracts with PG&E
provide that the CPUC has the authority to determine the appropriate utility
"avoided cost" to be used to set energy payments for certain QF contracts,
including those for all of our QF plants in California which sell power to PG&E.
Section 390 of the California Public Utility Code provides QFs the option to
elect to receive energy payments based on the PX market clearing price. In mid
2000, our QF facilities elected this option and were paid based upon the PX
Price from summer 2000 until January 19, 2001, when the PX ceased operating a
day ahead market. Since that time, the CPUC has ordered that the price to be
paid for energy deliveries by QFs electing the PX Price shall be based on a
natural gas cost-based "transition formula." The CPUC has conducted proceedings
(R.99-11-022) to determine whether the PX Price was the appropriate price for
the energy component upon which to base payments to QFs which had elected the
PX-based pricing option. The CPUC has issued a proposed decision to the effect
that the PX price was the appropriate price for energy payments under the
California Public Utility Code. However, a final decision has not been issued to
date. Therefore, it is possible that the CPUC could order a payment adjustment
based on a different energy price determination. We believe that the PX Price
was the appropriate price for energy payments but there can be no assurance that
this will be the outcome of the CPUC proceedings.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March
2001 Decision") proposing to change, on a prospective basis, the composition of
the short run avoided cost ("SRAC") energy price formula, which is reset
monthly, used by the California utilities in QF contracts. Prior to the March
2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50%
Malin border gas indices. In the March 2001 Decision, the CPUC changed this
formulation to eliminate the prices at Topock from the SRAC formula. The March
2001 Decision is subject to challenges at the CPUC and the FERC.
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the
"June 2001 Decision") that authorized the California utilities, including PG&E,
to amend QF contracts to elect a fixed energy price component that averages 5.37
cents per kilowatt-hour for a five-year term under those contracts in lieu of
using the SRAC energy price formula. By this order, the CPUC authorized the QF
contract energy price amendments without further CPUC concurrence. As part of
the agreement we entered into with PG&E pursuant to which PG&E, in bankruptcy,
agreed to assume its QF contracts with us, PG&E agreed with us to amend these
contracts to adopt the fixed price component that averages 5.37 cents pursuant
to the June 2001 Decision. This election became effective as of July 16, 2001.
As a result of the June 2001 Decision and our agreement with PG&E to amend the
QF contracts to adopt the fixed price energy component, the energy price
component in our QF contracts is now fixed for five years and we are no longer
subject to any uncertainty that may have existed with respect to this component
of our QF contract pricing as a result of the March 2001 Decision. Further, the
March 2001 Decision has no bearing on PG&E's agreement with us to assume the QF
contracts in bankruptcy or on the amount of the receivable that was so assumed.
As such, we have not reserved our PG&E receivables.
36
FERC Investigation into California Wholesale Markets -- On June 19, 2001, FERC
ordered price mitigation in 11 states in the western United States in an attempt
to reduce the dependence of the California market on spot markets in favor of
longer-term committed energy supplies. The order provides for price mitigation
in the spot market throughout the 11-state western region during "reserve
deficiency hours," which is when operating reserves in California fall below
seven percent. This price will be a single market clearing price based upon the
marginal operating cost of the last unit dispatched by the California ISO. In
addition, FERC implemented price mitigation in non-reserve deficiency hours,
which will be set at 85% of the market clearing price during the last reserve
deficiency period. These price mitigation procedures went into effect on June
20, 2001, and will remain in effect until September 30, 2002.
The retention by FERC of a market-based, rather than a cost-of-service-based,
rate structure, will enable us to continue to realize benefits from our
efficient, modern power plants. We believe that Calpine's marginal costs will
continue to be below any price cap imposed by FERC, whether during reserve
deficiency hours or at other times. Therefore, we believe that FERC's mitigation
plan will not have a material adverse effect on Calpine's financial condition or
results of operations.
FERC also ordered all sellers and buyers in wholesale power markets administered
by the California ISO, as well as representatives of the State of California, to
participate in a settlement conference before a FERC administrative judge. The
settlement discussions were intended to resolve all issues that remain
outstanding to resolve past accounts, including sellers' claims for unpaid
invoices, and buyers' claims for refunds of alleged overcharges, for past
periods. The settlement discussions began on June 25, 2001, and ended on July 9,
2001. The Chief Administrative Law Judge issued his report and recommendations
to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited
fact-finding hearing to calculate refunds for spot market transactions in
California. The hearing has been delayed pending the submission by the
California ISO and the California Power Exchange of data for the purpose of
developing the factual basis needed to implement the refund methodology and
order refunds. The FERC Administrative Law Judge presiding over this hearing
recently announced that this information must be submitted not later than
December 7, 2001, and the deadline for completion of the hearing is March 8,
2002. While it is not possible to predict the amount of any refunds until the
hearings take place, based upon the information available at this time, we do
not believe that this proceeding will result in a material adverse effect on
Calpine's financial condition or results of operations.
Financial Market Risks
Short-term investments -- As of September 30, 2001, we had short-term
investments of $137.7 million. These short-term investments consist of highly
liquid investments with maturities of less than three months. We have the
ability to hold these investments to maturity, and as a result, we would not
expect the value of these investments to be affected to any significant degree
by the effect of a sudden change in market interest rates.
Interest rate swaps and forward interest rate agreements -- From time to time,
we use interest rate swap agreements to mitigate our exposure to interest rate
fluctuations. We do not use interest rate swap agreements for speculative or
trading purposes. The following table summarizes the fair market value of our
existing interest rate swap agreements as of September 30, 2001 (dollars in
thousands):
WEIGHTED
NOTIONAL AVERAGE
PRINCIPAL INTEREST FAIR
MATURITY DATE AMOUNT RATE MARKET VALUE
- -------------- ---------- -------- ------------
2007 ......... $38,103 8.0% $(6,216)
2007 ......... 38,103 8.0 (6,199)
2007 ......... 29,757 7.9 (5,025)
2007 ......... 29,757 7.9 (5,009)
2008 ......... 300,000 5.0 (9,446)
2008 ......... 100,000 4.9 (2,943)
2008 ......... 50,000 4.8 (1,094)
2009 ......... 15,000 6.9 (1,593)
2011 ......... 54,434 6.9 (5,683)
2011 ......... 250,000 5.1 (7,634)
2012 ......... 119,385 6.5 (11,743)
2014 ......... 70,528 6.7 (6,969)
2015 ......... 22,500 7.0 (3,225)
2018 ......... 17,500 7.0 (2,692)
---------- --- --------
Total $1,135,067 5.8% $(75,471)
========== === ========
37
Energy price fluctuations -- As an independent power producer primarily focused
on generation of electricity using gas-fired turbines, our natural physical
commodity position is "short" (we require) gas and "long" (we own) power
capacity. To manage forward exposure to price fluctuation in these and (to a
lesser extent) other commodities, we enter into derivative commodity
instruments. All transactions are subject to our risk management policy which
prohibits positions that exceed production capacity and fuel requirements. Any
hedging, balancing or optimization activities that we engage in are directly
related to our asset-based business model of owning and operating gas-fired
electric power plants. We hedge exposures that arise from the ownership and
operation of power plants and related sales of electricity and purchases of
natural gas, and we utilize derivatives to optimize the returns we are able to
achieve from these assets for our shareholders. This model is markedly different
from that of companies that engage in commodity trading operations that are
unrelated to underlying physical assets. Derivative commodity instruments are
accounted for under the requirements of SFAS No. 133.
The fair value of outstanding derivative commodity instruments and the change in
fair value that would be expected from a ten percent adverse price change are
shown in the table below (in thousands):
CHANGE IN FAIR
VALUE FROM
10% ADVERSE
FAIR VALUE PRICE CHANGE
---------- --------------
At September 30, 2001:
Crude oil.................. $ 2,688 $ (5,797)
Electricity................ 469,307 (75,340)
Natural gas................ (592,424) (123,930)
--------- -----------
Total.................. $(120,429) $ (205,067)
========= ===========
Derivative commodity instruments included in the table are those included in
Note 8 to the unaudited Consolidated Condensed Financial Statements. The fair
value of derivative commodity instruments included in the table is based on
present value adjusted quoted market prices of comparable contracts. During the
nine months ended September 30, 2001, significant electricity price volatility
occurred in the western United States. The fair value of derivative commodity
instruments includes the effect of increased power prices versus our derivative
forward commitments. Derivative commodity instruments offset physical positions
exposed to the cash market. None of the offsetting physical positions are
included in the above table.
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 prompt month prices, the fair value of
Calpine's derivative portfolio would typically change less than that shown in
the table due to lower volatility in out-month prices.
The primary factors affecting the fair value of the Company's derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and Mwh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions increased 29%
from June 30, 2001 to September 30, 2001, while the total volume of open power
derivative positions increased 175% 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 the Company's derivatives
over time, driven both by price volatility and the increases in volume of open
derivative transactions. Under SFAS No. 133, the change since the last balance
sheet date in the total value of the derivatives (both assets and liabilities)
is reflected either in OCI, net of tax, or in the statement of operations as an
item (gain or loss) of current earnings. As of September 30, 2001, the majority
of the balance in accumulated OCI represented the unrealized net loss associated
with commodity cash flow hedging transactions. As noted above, there is a
substantial amount of volatility inherent in accounting for the fair value of
these derivatives, and the Company's results during 2001 have reflected this.
See Note 8 for additional information on derivative activity and also the Form
8-K filed on September 5, 2001 for a further discussion of the Company's
accounting policies related to derivative accounting. This treatment depends
upon whether the derivative is designated as a cash flow or fair value hedge or
whether the derivative is not designated in a hedge relationship. The following
accounting applies:
- Changes in the value of derivatives designated as cash flow
hedges, net of any ineffectiveness, are recorded to OCI.
- Changes in the value of derivatives designated as fair value
hedges are recorded in the statement of operations with the
offsetting change in value of the hedge item also recorded in
the statement of operations. Any difference between these two
entries to the statement of operations represents hedge
ineffectiveness.
- The change in value of derivatives not designated in hedge
relationships is recorded to the statement of operations.
38
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in ITEM 2.
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings.
Litigation -- An action was filed against Lockport Energy Associates, L.P. and
the New York Public Service Commission ("NYPSC") in August 1997 by New York
State Electricity and Gas Company ("NYSEG") in the Federal District Court for
the Northern District of New York. NYSEG requested the Court to direct NYPSC and
FERC to modify contract rates to be paid to the Lockport Power Plant. In October
1997, NYPSC filed a cross-claim alleging that the FERC violated the Public
Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and the Federal
Power Act by failing to reform the NYSEG contract that was previously approved
by the NYPSC. On September 29, 2000, the New York Federal District Court
dismissed NYSEG's complaint and NYPSC's cross-claim. The Court stated that FERC
has no authority to alter or waive its regulations or exemptions to alter the
terms of the applicable power purchase agreements and that Qualifying Facilities
are entitled to the benefit of their bargain, even if at the expense of NYSEG
and its ratepayers. NYSEG has filed an appeal with respect to this decision. In
any event, the Company retains the right to require The Brooklyn Union Gas
Company to purchase its interest in the Lockport Power Plant for $18.9 million,
less equity distributions received by the Company, at any time before December
19, 2001. On October 5, 2001, the United States Court of Appeals affirmed the
judgment of the federal district court and dismissed all of the claims raised by
NYSEG against Lockport.
The Company is involved in various other claims and legal actions arising out of
the normal course of business. The Company does not expect that the outcome of
these proceedings will have a material adverse effect on the Company's financial
position or results of operations.
ITEM 2. Changes in Securities and Use of Proceeds.
On April 19, 2001, Calpine closed the acquisition of all of the common shares of
Encal Energy Ltd., a Calgary, Alberta-based natural gas and petroleum
exploration and development company, through a stock-for-stock exchange in which
Encal shareholders received, in exchange for each share of Encal common stock,
.1493 shares of Calpine common equivalent shares (called "exchangeable shares")
of Calpine's subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633
exchangeable shares were issued to Encal shareholders in exchange for their
Encal common stock. Each exchangeable share is exchangeable for one share of
Calpine common stock until April 19, 2002, at which date all remaining
exchangeable shares will automatically be exchanged for shares of Calpine common
stock.
The exchangeable shares and the underlying shares of Calpine common stock were
issued without registration under the Securities Act of 1933 in reliance upon
the exemption afforded by Section 3(a)(10) thereby. While no shares of Calpine
common stock were issued to Encal shareholders as part of the closing of the
acquisition on April 19, 2001, exchanges have been occurring from time to time
since that date. Calpine is hereby reporting the issuance of all 16,603,633
shares of Calpine common stock underlying the exchangeable shares, although some
exchangeable shares remain unconverted at this time.
ITEM 4. Submission of Matters to a Vote of Security Holders.
As previously reported, on July 16, 2001, we announced that Michael Polsky had
resigned from the Board of Directors and on July 17, 2001, we announced the
appointment of Gerald Greenwald to the Board of Directors.
ITEM 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT
NUMBER DESCRIPTION
------ -----------
*2.1 Combination Agreement, dated as of February 7, 2001, by and between
Calpine Corporation and Encal Energy Ltd. (a)
39
EXHIBIT
NUMBER DESCRIPTION
------ -----------
*2.2 Amending Agreement to the Combination Agreement, dated as of March 16,
2001, between Calpine Corporation and Encal Energy Ltd. (b)
*2.3 Form of Plan of Arrangement Under Section 186 of the Business
Corporations Act (Alberta) (included as Exhibit A to Exhibit 2.1)
Involving and Affecting Encal Energy Ltd. and the Holders of its Common
Shares and Options
*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation (c)
*3.2 Certificate of Correction of Calpine Corporation (d)
*3.3 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of Calpine Corporation (e)
*3.4 Certificate of Designation of Series A Participating Preferred Stock of
Calpine Corporation (d)
*3.5 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation (d)
*3.6 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation (e)
*3.7 Certificate of Designation of Special Voting Preferred Stock of Calpine
Corporation(m)
*3.8 Amended and Restated By-laws of Calpine Corporation (f)
*4.1 Form of Exchangeable Share Provisions and Other Provisions to Be
Included in the Articles of Calpine Canada Holdings Ltd. (included as
Exhibit B to Exhibit 2.1)
*4.2 Form of Support Agreement between Calpine Corporation and Calpine
Canada Holdings Ltd. (included as Exhibit C to Exhibit 2.1)
*4.3 Indenture dated as of August 10, 2000, between Calpine Corporation and
Wilmington Trust Company, as Trustee(g)
*4.4 First Supplemental Indenture dated as of September 28, 2000, between
Calpine Corporation and Wilmington Trust Company, as Trustee(h)
*4.5 Indenture dated as of April 25, 2001, between Calpine Canada Energy
Finance ULC and Wilmington Trust Company, as Trustee (i)
*4.6 Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation
as guarantor of debt securities of Calpine Canada Energy Finance ULC
(j)
*4.7 Amended and Restated Indenture dated as of October 16, 2001, between
Calpine Canada Energy Finance ULC and Wilmington Trust Company, as
Trustee (j)
*4.8 First Amendment to Guarantee Agreement dated as of October 16, 2001,
between Calpine Corporation and Wilmington Trust Company (j)
*4.9 Indenture dated as of October 18, 2001, between Calpine Canada Energy
Finance II ULC and Wilmington Trust Company, as Trustee (j)
*4.10 First Supplemental Indenture dated as of October 18, 2001, between
Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as
Trustee (j)
*4.11 Guarantee Agreement dated as of October 18, 2001, between Calpine
Corporation and Wilmington Trust Company (j)
*4.12 First Amendment to Guarantee Agreement dated as of October 18, 2001,
between Calpine Corporation and Wilmington Trust Company (j)
*4.13 Rights Agreement, dated as of June 5, 1997, between Calpine Corporation
and First Chicago Trust Company of New York, as Rights Agent (k)
*9.1 Form of Voting and Exchange Trust Agreement between Calpine
Corporation, Calpine Canada Holdings Ltd. and CIBC Mellon Trust
Company, as Trustee (included as Exhibit D to Exhibit 2.1)
*10.1 Amended and Restated Credit Agreement, dated as of February 15, 2001,
among Calpine Construction Finance Company, L.P., The Bank of Nova
Scotia, as Administrative Agent, and the Banks party thereto (l)
________________
* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly
Report on Form 10-Q dated June 30, 2001 and filed on August
14, 2001 (File No. 1-12079).
40
(b) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-56712).
(c) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3 (File No. 333-40652).
(d) 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.
(e) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3 (File No. 333-66078).
(f) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-67446).
(g) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-72583).
(h) Incorporated by reference to Calpine Corporation's Annual
Report on Form 10-K dated December 31, 2000 and filed on March
15, 2001 (File No. 001-12079).
(i) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-57338).
(j) Incorporated by reference to Calpine Corporation's Current
Report on Form 8-K dated October 16, 2001 and filed on
November 13, 2001 (File No. 001-12079).
(k) Incorporated by reference to Calpine Corporation's
Registration Statement on Form 8-A/A filed with the SEC on
September 28, 2001 (File No. 001-12079).
(l) Approximately 24 pages of this exhibit have been omitted
pursuant to a request for confidential treatment. The omitted
language has been filed separately with the Securities and
Exchange Commission.
(m) Incorporated by reference to Calpine Corporation's Quarterly
Report on Form 10-Q dated March 31, 2001 and filed on May 15,
2001 (File No. 001-12079).
(b) Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the quarter ended
September 30, 2001:
DATE OF REPORT DATE FILED ITEM REPORTED
-------------- ---------- -------------
July 6, 2001 July 9, 2001 5, 7
July 12, 2001 July 13, 2001 5, 7
July 16, 2001 July 17, 2001 5, 7
July 26, 2001 July 27, 2001 5, 7
August 14, 2001 September 5, 2001 5
December 31, 2000 September 10, 2001 5, 7
September 19, 2001 September 28, 2001 5, 7
41
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/ Ann B. Curtis Date: February 13, 2002
----------------------------------------
Ann B. Curtis
Executive Vice President
(Chief Financial Officer)
By: /s/ Charles B. Clark, Jr. Date: February 13, 2002
----------------------------------------
Charles B. Clark, Jr.
Senior Vice President and
Corporate Controller
(Chief Accounting Officer)
42
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------ -----------
*2.1 Combination Agreement, dated as of February 7, 2001, by and between
Calpine Corporation and Encal Energy Ltd. (a)
*2.2 Amending Agreement to the Combination Agreement, dated as of March 16,
2001, between Calpine Corporation and Encal Energy Ltd. (b)
*2.3 Form of Plan of Arrangement Under Section 186 of the Business
Corporations Act (Alberta) (included as Exhibit A to Exhibit 2.1)
Involving and Affecting Encal Energy Ltd. and the Holders of its Common
Shares and Options
*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation (c)
*3.2 Certificate of Correction of Calpine Corporation (d)
*3.3 Certificate of Amendment of Amended and Restated Certificate of
Incorporation of Calpine Corporation (e)
*3.4 Certificate of Designation of Series A Participating Preferred Stock of
Calpine Corporation (d)
*3.5 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation (d)
*3.6 Amended Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation (e)
*3.7 Certificate of Designation of Special Voting Preferred Stock of Calpine
Corporation (m)
*3.8 Amended and Restated By-laws of Calpine Corporation (f)
*4.1 Form of Exchangeable Share Provisions and Other Provisions to Be
Included in the Articles of Calpine Canada Holdings Ltd. (included as
Exhibit B to Exhibit 2.1)
*4.2 Form of Support Agreement between Calpine Corporation and Calpine
Canada Holdings Ltd. (included as Exhibit C to Exhibit 2.1)
*4.3 Indenture dated as of August 10, 2000, between Calpine Corporation and
Wilmington Trust Company, as Trustee(g)
*4.4 First Supplemental Indenture dated as of September 28, 2000, between
Calpine Corporation and Wilmington Trust Company, as Trustee(h)
*4.5 Indenture dated as of April 25, 2001, between Calpine Canada Energy
Finance ULC and Wilmington Trust Company, as Trustee (i)
*4.6 Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation
as guarantor of debt securities of Calpine Canada Energy Finance ULC
(j)
*4.7 Amended and Restated Indenture dated as of October 16, 2001, between
Calpine Canada Energy Finance ULC and Wilmington Trust Company, as
Trustee (j)
*4.8 First Amendment to Guarantee Agreement dated as of October 16, 2001,
between Calpine Corporation and Wilmington Trust Company (j)
*4.9 Indenture dated as of October 18, 2001, between Calpine Canada Energy
Finance II ULC and Wilmington Trust Company, as Trustee (j)
*4.10 First Supplemental Indenture dated as of October 18, 2001, between
Calpine Canada Energy Finance II ULC and Wilmington Trust Company, as
Trustee (j)
*4.11 Guarantee Agreement dated as of October 18, 2001, between Calpine
Corporation and Wilmington Trust Company (j)
*4.12 First Amendment to Guarantee Agreement dated as of October 18, 2001,
between Calpine Corporation and Wilmington Trust Company (j)
*4.13 Rights Agreement, dated as of June 5, 1997, between Calpine Corporation
and First Chicago Trust Company of New York, as Rights Agent (k)
*9.1 Form of Voting and Exchange Trust Agreement between Calpine
Corporation, Calpine Canada Holdings Ltd. and CIBC Mellon Trust
Company, as Trustee (included as Exhibit D to Exhibit 2.1)
*10.1 Amended and Restated Credit Agreement, dated as of February 15, 2001,
among Calpine Construction Finance Company, L.P., The Bank of Nova
Scotia, as Administrative Agent, and the Banks party thereto (l)
43
_________________
* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly
Report on Form 10-Q dated June 30, 2001 and filed on August
14, 2001 (File No. 1-12079).
(b) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-56712).
(c) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3 (File No. 333-40652).
(d) 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.
(e) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3 (File No. 333-66078).
(f) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-67446).
(g) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-72583).
(h) Incorporated by reference to Calpine Corporation's Annual
Report on Form 10-K dated December 31, 2000 and filed on March
15, 2001 (File No. 001-12079).
(i) Incorporated by reference to Calpine Corporation's
Registration Statement on Form S-3/A (File No. 333-57338).
(j) Incorporated by reference to Calpine Corporation's Current
Report on Form 8-K dated October 16, 2001 and filed on
November 13, 2001 (File No. 001-12079).
(k) Incorporated by reference to Calpine Corporation's
Registration Statement on Form 8-A/A filed with the SEC on
September 28, 2001 (File No. 001-12079).
(l) Approximately 24 pages of this exhibit have been omitted
pursuant to a request for confidential treatment. The omitted
language has been filed separately with the Securities and
Exchange Commission.
(m) Incorporated by reference to Calpine Corporation's Quarterly
Report on Form 10-Q dated March 31, 2001 and filed on May 15,
2001 (File No. 001-12079).
44