UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 for the quarterly period ended June 30, 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:
304,986,024 shares of Common Stock, par value $.001 per share, outstanding on
August 13, 2001
CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Quarter Ended June 30, 2001
INDEX
Page No.
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements.
Consolidated Condensed Balance Sheets
June 30, 2001 and December 31, 2000.................................................... 3
Consolidated Condensed Statements of Operations
For the Three and Six Months Ended June 30, 2001 and 2000.............................. 4
Consolidated Condensed Statements of Cash Flows
For the Six Months Ended June 30, 2001 and 2000........................................ 5
Notes to Consolidated Condensed Financial Statements
June 30, 2001.......................................................................... 6
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk................................ 25
PART II - OTHER INFORMATION
ITEM 2. Change in Securities and Use of Proceeds.................................................. 25
ITEM 4. Submission of Matters to a Vote of Security Holders....................................... 25
ITEM 6. Exhibits and Reports on Form 8-K.......................................................... 26
Signatures.................................................................................................. 28
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
June 30, 2001 and December 31, 2000
(in thousands, except share and per share amounts)
(unaudited)
June 30, December 31,
2001 2000
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents .................................................... $ 1,241,520 $ 596,077
Accounts receivable, net of allowance of $17,521 and $11,555 ................. 1,046,080 727,893
Inventories .................................................................. 56,615 44,456
Prepaid expense .............................................................. 77,239 27,515
Other current assets ......................................................... 1,087,610 41,165
------------ ------------
Total current assets ...................................................... 3,509,064 1,437,106
------------ ------------
Property, plant and equipment, net .............................................. 10,399,454 7,979,160
Investments in power projects ................................................... 261,189 205,621
Project development costs ....................................................... 92,001 38,597
Notes receivable ................................................................ 354,301 217,927
Restricted cash ................................................................. 97,949 88,618
Deferred financing costs ........................................................ 159,949 112,049
Other assets .................................................................... 1,145,158 244,125
------------ ------------
Total assets .............................................................. $ 16,019,065 $ 10,323,203
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and borrowings under lines of credit, current portion .......... $ 1,258 $ 1,087
Accounts payable ............................................................. 914,960 843,641
Zero-Coupon Convertible Debentures Due 2021 .................................. 1,000,000 --
Project financing, current portion ........................................... 1,396 58,486
Capital lease obligation, current portion .................................... 2,251 1,985
Income taxes payable ......................................................... -- 63,409
Accrued payroll and related expense .......................................... 57,038 53,667
Accrued interest payable ..................................................... 126,130 77,878
Other current liabilities .................................................... 897,281 149,080
------------ ------------
Total current liabilities ................................................. 3,000,314 1,249,233
------------ ------------
Notes payable and borrowings under lines of credit, net of current portion ...... 10,587 455,067
Project financing, net of current portion ....................................... 1,776,435 1,473,869
Senior notes .................................................................... 5,096,750 2,551,750
Capital lease obligation, net of current portion ................................ 208,839 208,876
Deferred income taxes, net ...................................................... 768,057 620,807
Deferred lease incentive ........................................................ 58,989 60,676
Deferred revenue ................................................................ 102,581 92,511
Other liabilities ............................................................... 985,287 30,529
------------ ------------
Total liabilities ......................................................... 12,007,839 6,743,318
------------ ------------
Company-obligated mandatorily redeemable
convertible preferred securities of subsidiary trusts ........................ 1,122,706 1,122,490
Minority interests .............................................................. 40,733 37,576
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000
shares; issued and outstanding none 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
304,162,586 shares in 2001 and 300,074,078 shares in 2000 ................. 304 300
Additional paid-in capital ................................................... 1,993,849 1,896,987
Retained earnings ............................................................ 775,223 547,895
Accumulated other comprehensive income (loss) ................................ 78,411 (25,363)
------------ ------------
Total stockholders' equity ................................................ 2,847,787 2,419,819
------------ ------------
Total liabilities and stockholders' equity ................................ $ 16,019,065 $ 10,323,203
============ ============
The accompanying notes are an integral part of
these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2001 and 2000
(in thousands, except per share amounts)
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
Revenue:
Electric generation and marketing revenue ........................ $ 1,257,340 $ 341,611 $ 2,307,407 $ 547,679
Oil and gas production and marketing revenue ..................... 343,012 69,652 628,871 136,627
Income from unconsolidated investments in power projects ......... 1,600 4,843 2,163 14,617
Other revenue .................................................... 10,921 1,050 14,183 3,431
----------- ----------- ----------- -----------
Total revenue ................................................ 1,612,873 417,156 2,952,624 702,354
----------- ----------- ----------- -----------
Cost of revenue:
Electric generation and marketing expense ........................ 731,497 78,722 1,283,232 131,607
Oil and gas production and marketing expense ..................... 245,638 25,104 398,549 55,543
Fuel expense ..................................................... 228,430 104,044 485,444 177,696
Depreciation expense ............................................. 72,144 50,702 144,157 95,815
Operating lease expense .......................................... 27,449 10,672 55,460 21,130
Other expense .................................................... 3,490 1,280 5,989 2,780
----------- ----------- ----------- -----------
Total cost of revenue ........................................ 1,308,648 270,524 2,372,831 484,571
----------- ----------- ----------- -----------
Gross profit ................................................. 304,225 146,632 579,793 217,783
Project development expense ......................................... 4,372 5,228 20,211 9,390
General and administrative expense .................................. 50,537 18,508 86,622 28,740
Nonrecurring merger cost ............................................ 35,606 -- 41,627 --
----------- ----------- ----------- -----------
Income from operations ....................................... 213,710 122,896 431,333 179,653
Other expense (income):
Interest expense ................................................. 43,331 18,202 63,256 39,955
Distributions on trust preferred securities ...................... 15,387 9,085 30,562 16,063
Interest income .................................................. (20,531) (5,615) (39,889) (13,177)
Other expense (income), net ...................................... (3,291) 178 (9,018) (380)
----------- ----------- ----------- -----------
Income before provision for income taxes ..................... 178,814 101,046 386,422 137,192
Provision for income taxes .......................................... 69,849 41,538 158,830 56,583
----------- ----------- ----------- -----------
Income before extraordinary charge and cumulative effect of a
change in accounting principle .............................. 108,965 59,508 227,592 80,609
Extraordinary charge, net of tax benefit of $834 .................... (1,300) -- (1,300) --
Cumulative effect of a change in accounting principle ............... -- -- 1,036 --
----------- ----------- ----------- -----------
Net income ................................................... $ 107,665 $ 59,508 $ 227,328 $ 80,609
=========== =========== =========== ===========
Basic earnings per common share:
Weighted average shares of common stock outstanding ............ 302,729 271,505 301,641 270,516
Income before extraordinary charge and cumulative effect of a
change in accounting principle .............................. $ 0.36 $ 0.22 $ 0.75 $ 0.30
Extraordinary charge ........................................... $ -- $ -- $ -- $ --
Cumulative effect of a change in accounting principle .......... $ -- $ -- $ -- $ --
----------- ----------- ----------- -----------
Net income ..................................................... $ 0.36 $ 0.22 $ 0.75 $ 0.30
=========== =========== =========== ===========
Diluted earnings per common share:
Weighted average shares of common stock outstanding before
dilutive effect of certain convertible securities ............. 318,255 287,271 317,544 286,439
Income before dilutive effect of certain convertible securities,
extraordinary charge and change in accounting principle ....... $ 0.34 $ 0.21 $ 0.72 $ 0.28
Dilutive effect of certain convertible securities (1) .......... $ (0.02) $ (0.01) $ (0.04) $ --
----------- ----------- ----------- -----------
Income before extraordinary charge and cumulative effect of a
change in accounting principle .............................. $ 0.32 $ 0.20 $ 0.68 $ 0.28
Extraordinary charge ........................................... $ -- $ -- $ -- $ --
Cumulative effect of a change in accounting principle .......... $ -- $ -- $ -- $ --
----------- ----------- ----------- -----------
Net income ..................................................... $ 0.32 $ 0.20 $ 0.68 $ 0.28
=========== =========== =========== ===========
(1) Includes the effect of the assumed conversion of certain convertible
securities. For the three and six months ended June 30, 2001, the assumed
conversion calculation adds 41,964 and 49,379 shares of common stock and
$7,507 and $20,838 to the net income results, representing the after tax
expense on certain convertible securities avoided upon conversion. For the
three and six months ended June 30, 2000, the assumed conversion
calculation adds 18,912 shares of common stock and $2,439 and $4,878 to the
net income results.
The accompanying notes are an integral part of these
consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2001 and 2000
(in thousands)
(unaudited)
Six Months Ended June 30,
2001 2000
----------- -----------
Cash flows from operating activities:
Net income ........................................ $ 227,328 $ 80,609
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization .................. 148,552 102,893
Deferred income taxes, net ..................... 123,937 5,960
Income from unconsolidated investments in
power projects ................................ (2,163) (14,617)
Distributions from unconsolidated power projects 2,459 19,413
Minority interest .............................. 3,157 407
Change in long-term liabilities ................ 1,061,206 --
Change in operating assets and liabilities, net
of effects of acquisitions:
Accounts receivable ............................ (315,344) (105,688)
Inventories .................................... (12,159) (953)
Other current assets ........................... (1,072,306) (9,906)
Notes receivable ............................... (43,624) (16,955)
Other assets ................................... (901,012) 11,866
Accounts payable and accrued expense ........... 131,502 40,358
Other current liabilities and deferred revenue . 749,190 (39,944)
----------- -----------
Net cash provided by operating activities ... 100,723 73,443
----------- -----------
Cash flows from investing activities:
Purchases of property, plant and equipment ........ (2,556,789) (968,475)
Acquisitions, net of cash acquired ................ (252) (201,823)
Capital expenditures on joint ventures ............ (63,871) (134,561)
Maturities of collateral securities ............... 2,885 3,315
Project development costs ......................... (55,314) (47,767)
Decrease in notes receivable ...................... (93,723) (32,040)
Increase in restricted cash ....................... (24,705) (192)
Other ............................................. 8,384 --
----------- -----------
Net cash used in investing activities ....... (2,783,385) (1,381,543)
----------- -----------
Cash flows from financing activities:
Proceeds from notes payable and borrowings
under lines of credit ........................... 258 443,776
Repayments of notes payable and borrowings
under lines of credit ........................... (444,568) (9,159)
Borrowings from project financing ................. 1,479,673 361,965
Repayments of project financing ................... (1,234,433) --
Proceeds from issuance of senior notes ............ 2,650,000 --
Repayments of senior notes ........................ (105,000) --
Proceeds from issuance of convertible securities .. 1,000,000 360,000
Proceeds from issuance of common stock ............ 49,369 6,519
Financing costs ................................... (64,534) (25,099)
Other ............................................. (2,660) 8,504
----------- -----------
Net cash provided by financing activities ... 3,328,105 1,146,506
----------- -----------
Net increase (decrease) in cash and cash equivalents . 645,443 (161,594)
Cash and cash equivalents, beginning of period ....... 596,077 349,371
----------- -----------
Cash and cash equivalents, end of period ............. $ 1,241,520 $ 187,777
=========== ===========
Cash paid during the period for:
Interest .......................................... $ 208,903 $ 94,911
Income taxes ...................................... $ 114,083 $ 37,113
The accompanying notes are an integral part of
these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 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 and Canada. In pursuing this single business strategy, 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 and Canada. 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
(see Note 6). 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 included in the Company's annual report on
Form 10-K for the year ended December 31, 2000. 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 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, and the Company's policy prohibits positions
that exceed production capacity and fuel requirements. 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 does not believe there is a significant risk of
non-performance by the counterparties.
New Accounting Pronouncements -- In July 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". SFAS No. 141
eliminates the pooling-of-interests method of accounting for business
combinations and modifies the application of the purchase accounting method. 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 impact on its consolidated financial statements.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and 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 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 impact 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. Derivative Instruments
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Company currently holds four classes of
derivative instruments that are impacted by the new pronouncement - interest
rate swaps, 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 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 contracts being hedged. The changes in fair values of derivative
instruments that are not designated as hedges are recorded in current earnings.
The FASB has 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 on Electricity for the
Normal Purchases and Normal Sales Exception"). As a result, certain capacity
sales contracts currently held by the Company 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 June 30, 2001 for the Company's derivative
instruments.
Commodity Total
Interest Rate Derivative Derivative
Swaps Instruments Instruments
------------- ----------- -----------
Current derivative asset (1) ..................................... $ -- $ 1,048,198 $ 1,048,198
Long-term derivative asset (2) ................................... -- 874,306 874,306
----------- ----------- -----------
Total assets .................................................. $ -- $ 1,922,504 $ 1,922,504
=========== =========== ===========
Current derivative liability (3) ................................. $ 12,886 $ 677,045 $ 689,931
Long-term derivative liability (4) ............................... 13,000 944,448 957,448
----------- ----------- -----------
Total liabilities ........................................... $ 25,886 $ 1,621,493 $ 1,647,379
=========== =========== ===========
Total comprehensive income (loss) ................................ $ (25,937) $ 176,933 $ 150,996
Reclassification adjustment for activity included in net income .. -- 21,792 21,792
Income tax benefit (expense) ..................................... 8,970 (78,406) (69,436)
----------- ----------- -----------
Net comprehensive income (loss) ............................. $ (16,967) $ 120,319 $ 103,352
=========== =========== ===========
(1) Included in other current assets
(2) Included in other assets
(3) Included in other current liabilities
(4) Included in other liabilities
During the three and six months ended June 30, 2001, the Company recognized
gains on derivatives not designated as hedges of $67.2 million and $69.7
million, respectively, which were recorded in electric generation and marketing
revenue, and $27.4 and $34.5 million, respectively, which were recorded in fuel
expense.
During the three and six months ended June 30, 2001, the Company recognized
pretax losses of $4.0 million and $3.5 million, respectively, related to hedge
ineffectiveness on gas contracts, which are included in fuel expense. For the
three and six months ended June 30, 2001, the Company recognized pretax gains of
$1.2 million and zero, respectively, related to hedge ineffectiveness on
electricity contracts, which are included in electric generation and marketing
revenue. The Company did not exclude any components of derivative instruments
from the assessment of hedge effectiveness.
As of June 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 17.5 years. The Company estimates that pretax gains of $358.3
million will be reclassified from accumulated OCI into earnings during the next
twelve months as the hedged transactions affect earnings.
4. Property, Plant and Equipment, Net and Capitalized Interest
Property, plant and equipment, net consisted of the following (in thousands):
June 30, December 31,
2001 2000
------------ ------------
Geothermal properties ........................... $ 356,089 $ 334,585
Oil and gas properties .......................... 1,666,933 1,441,175
Buildings, machinery and equipment .............. 2,982,315 1,951,250
Power sales agreements .......................... 139,932 162,086
Gas contracts ................................... 143,619 129,999
Other ........................................... 190,065 145,877
------------ -----------
5,478,953 4,164,972
Less accumulated depreciation and amortization .. (828,384) (614,816)
------------ -----------
4,650,569 3,550,156
Land ........................................... 68,630 12,578
Construction in progress ....................... 5,680,255 4,416,426
------------ -----------
Property, plant and equipment, net ............. $ 10,399,454 $ 7,979,160
============ ===========
Construction in progress is primarily attributable to gas-fired projects under
construction. Upon commencement of 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 six months
ended June 30, 2001 and 2000, the Company recorded net interest expense of $63.3
million and $40.0 million, respectively, after capitalizing $153.7 million and
$52.0 million, respectively, of interest on general corporate funds used for
construction and after recording $65.9 million and $15.3 million, respectively,
of interest capitalized on funds borrowed for specific construction projects.
Upon commencement of plant operation, capitalized interest, as a component of
the total cost of the plant, is amortized over the estimated useful life of the
plant. The increase in the amount of interest capitalized during the six months
ended June 30, 2001, reflects the significant increase in the Company's power
plant construction program.
5. Notes Receivable
As of June 30, 2001 and December 31, 2000, the components of notes receivable
were (in thousands):
June 30, December 31,
2001 2000
--------- ------------
PG&E note .................................. $ 84,208 $ 62,336
Delta note ................................. 243,402 112,050
Other ...................................... 38,237 43,724
--------- ---------
Total notes receivable ............ 365,847 218,110
Less: Notes receivable, current portion .... (11,546) (183)
--------- ---------
Notes receivable, net of current portion.... $ 354,301 $ 217,927
========= =========
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 a note from the
project, Delta Energy Center, LLC, bearing interest at 11.37% per annum.
6. Acquisitions and Asset Purchases
On April 3, 2001, the Company acquired all of the common shares of WRMS
Engineering, Inc. ("WRMS"), a California-based engineering and architectural
firm, through a stock-for-stock exchange in which WRMS shareholders received a
total of 151,176 shares of Calpine common stock. The aggregate value of the
transaction was approximately $7.8 million, including the assumed indebtedness
of WRMS.
On April 11, 2001, the Company acquired the development rights from Enron North
America for the 750-megawatt natural gas-fired Pastoria Energy Center planned
for Kern County, California. The project was licensed by the California Energy
Commission in December 2000. Construction began in June 2001 and commercial
operation is scheduled for the summer of 2003.
On April 17, 2001, the Company acquired the development rights from Kirkland,
Washington-based National Energy Systems Company for the 248-megawatt natural
gas-fired Goldendale Energy Center planned for Goldendale, Washington. Energy
generated from the Goldendale facility will be sold directly into the Northwest
Power Pool. Construction commenced in April 2001, and energy deliveries are
scheduled to begin July 1, 2002.
On April 17, 2001, the Company acquired assets of The Bayless Companies and its
partners with reserves located in the western portion of the San Juan Basin in
New Mexico. Currently 35 wells produce approximately 6 million cubic feet
equivalent per day ("mmcfe/d"), 96 percent of which is natural gas.
On April 19, 2001, the Company acquired all of the common shares of Encal Energy
Ltd. ("Encal") (which was thereafter merged with and into Calpine Canada
Resources 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 the
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. The aggregate value of the transaction was approximately U.S. $1.1
billion, including the assumed indebtedness of Encal. The transaction was
accounted for under the pooling-of-interests method and, accordingly, all
historical amounts reflected in the consolidated condensed financial statements
have been restated to reflect the transaction. To date, the Company incurred
$41.6 million in nonrecurring merger costs for this transaction. With the
addition of Encal's assets, which currently produce approximately 230 mmcfe per
day, net of royalties, Calpine's net production increased to 390 mmcfe per day
in North America, enough to fuel approximately 2,300 megawatts of its power
fleet.
7. Project Financing
In connection with financings in the second quarter (see Notes 8 and 9), the
Company repaid approximately $874 million of its project financing. The Company
drew $870.1 million on the Calpine Construction Finance Company debt revolvers
during the quarter.
8. Senior Notes
On April 25, 2001, Calpine Canada Energy Finance ULC ("Energy Finance"), the
Company's indirect wholly owned subsidiary, issued $1.5 billion in aggregate
principal amount of its 8 1/2% Senior Notes Due 2008. The Energy Finance Senior
Notes Due 2008 are fully and unconditionally guaranteed by the Company.
On June 7, 2001, the Company redeemed all $105 million in aggregate outstanding
principal amount of its 9 1/4% Senior Notes Due 2004 at a redemption price of
100% of the principal amount plus accrued interest to the redemption date. As a
result, the Company recorded a $1.3 million extraordinary charge related to
writing off the unamortized balance of deferred financing costs.
9. Zero-Coupon Convertible Debentures
On April 30, 2001, the Company completed the sale of $1.0 billion of Zero-Coupon
Convertible Debentures Due 2021 in a private placement under Rule 144A of the
Securities Act of 1933. The securities are convertible into Calpine common
shares at a price of $75.35 at the option of the holder at any time. Holders
have the right to require the Company to repurchase their debentures in 2002,
2004, 2006, 2008, 2011 and 2016 at a specified price in cash or Calpine common
stock at the Company's option, except in 2016 when the repurchase price must be
paid in cash. The debentures are redeemable at the option of the Company after
2004 at a specified price in cash or Calpine common stock. As the holders of the
debentures have the right to require the Company to repurchase the debentures
within a year, the debentures are classified as current.
10. Equity
In the second quarter of 2001, the Company's shareholders approved an amendment
to the Articles of Incorporation, which increased the number of authorized
shares of common stock to 1,000,000,000. In addition, the Board of Directors
voted to increase the number of authorized shares of Series A Participating
Preferred Stock to 1,000,000 shares.
11. 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.
Total comprehensive income is summarized as follows (in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ---------------------
2001 2000 2001 2000
--------- -------- --------- --------
Net income ...................................... $ 107,665 $ 59,508 $ 227,328 $ 80,609
--------- -------- --------- --------
Other comprehensive income:
Unrealized gain on cash flow hedges ........ 260,957 -- 172,788 --
Gain on foreign currency translation ....... 2,914 -- 422 --
Income tax expense ......................... (104,035) -- (69,436) --
--------- -------- --------- --------
Other comprehensive income, net of tax .. 159,836 -- 103,774 --
--------- -------- --------- --------
Total comprehensive income ...................... $ 267,501 $ 59,508 $ 331,102 $ 80,609
========= ======== ========= ========
12. Significant Customers
The Company's significant customers at June 30, 2001, were PG&E and Enron Power
Marketing. Due to the increase in volume in CES transactions, Enron Power
Marketing has become a significant customer, exceeding 10% of the Company's
revenue for the six months ended June 30, 2001, and 10% of the accounts
receivable balance at June 30, 2001. Revenues earned from Enron were $340.9
million and $1.3 million for the six months ended June 30, 2001 and 2000,
respectively. Receivables were $147.5 million and $46.0 million at June 30, 2001
and December 31, 2000, respectively. The receivables at June 30, 2001, were
current and continue to be paid currently.
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. See Note 16 for an update of the PG&E bankruptcy proceedings.
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 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.
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 agreed
to assume its QF contracts with Calpine in bankruptcy, 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 six months ended June 30, 2001 and
2000 were as follows (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2001 2000 2001 2000
-------- -------- -------- --------
Revenues:
PG&E ................. $119,027 $ 97,870 $289,995 $139,029
Receivables at June 30, 2001, April 6, 2001, and December 31, 2000, were as
follows (in thousands):
June 30, 2001 April 6, 2001 December 31, 2000
------------- ------------- -----------------
Receivables:
PG&E accounts receivable .... $291,991 $265,588 $204,448
PG&E has paid currently for energy deliveries made after April 6, 2001, the PG&E
bankruptcy filing date.
The Company had a combined accounts receivable balance of $14.2 million as of
June 30, 2001, from the California Independent System Operator Corporation
("CAISO") and Automated Power Exchange, Inc. ("APX"). 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 impacted by PG&E's ability to pay the California Power
Exchange, which in turn pays APX for energy deliveries by the Company through
APX. The Company has provided a full reserve against collection uncertainties
for these receivables. See Note 16 for an update on the Federal Energy
Regulatory Commission ("FERC") investigation into the California wholesale
markets.
The Company also had an accounts receivable balance of $26.2 million as of June
30, 2001, from the California Department of Water Resources. These receivables
at June 30, 2001, were current and continue to be paid currently.
13. 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 purchased gas expense, 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
related purposes, 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.
Although the Company believes it is most meaningful to review the combined total
of electric generation and marketing revenue, the table below shows the relative
levels and growth of power and gas hedging, balancing and related activity.
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
Sales of purchased power ... $ 683,196 $ 28,977 $1,136,798 $ 41,121
Sales of purchased gas ..... 226,693 7,727 355,865 16,331
---------- ---------- ---------- ----------
Total ............. $ 909,889 $ 36,704 $1,492,663 $ 57,452
========== ========== ========== ==========
Purchased power expense .... $ 655,322 $ 31,605 $1,111,588 $ 42,852
Purchased gas expense ...... 218,330 7,480 336,958 15,219
---------- ---------- ---------- ----------
Total ............. $ 873,652 $ 39,085 $1,448,546 $ 58,071
========== ========== ========== ==========
14. 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 June 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 .................... $ 108,965 302,729 $ 0.36 $ 59,508 271,505 $ 0.22
Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- --
Cumulative effect of a change in accounting principle,
net of tax .................................................... -- -- -- -- -- --
--------- ------- ------ -------- ------- ------
Net income ...................................................... $ 107,665 302,729 $ 0.36 $ 59,508 271,505 $ 0.22
========= ======= ====== ======== ======= ======
Common shares issuable upon exercise of stock options
using treasury stock method ................................... 15,526 15,766
------- -----
Diluted earnings per common share:
Income before dilutive effect of certain convertible
securities, extraordinary charge and cumulative effect
of a change in accounting principle ........................... $ 108,965 318,255 $ 0.34 $ 59,508 287,271 $ 0.21
Dilutive effect of certain convertible securities ............... 7,507 41,964 (0.02) 2,439 18,912 (0.01)
--------- ------- ------ -------- ------- ------
Income before extraordinary charge and cumulative effect
of a change in accounting principle ........................... 116,472 360,219 0.32 61,947 306,183 0.20
Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- --
Cumulative effect of a change in accounting principle,
net of tax .................................................... -- -- -- -- -- --
--------- ------- ------ -------- ------- ------
Net income ...................................................... $ 115,172 360,219 $ 0.32 $ 61,947 306,183 $ 0.20
========= ======= ====== ======== ======= ======
SIX MONTHS:
Basic earnings per common share:
Income before extraordinary charge and cumulative
effect of a change in accounting principle .................... $ 227,592 301,641 $ 0.75 $ 80,609 270,516 $ 0.30
Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- --
Cumulative effect of a change in accounting principle,
net of tax .................................................... 1,036 -- -- -- -- --
--------- ------- ------ -------- -------- ------
Net income ...................................................... $ 227,328 301,641 $ 0.75 $ 80,609 270,516 $ 0.30
========= ======= ====== ======== ======= ======
Common shares issuable upon exercise of stock options
using treasury stock method ................................... 15,903 15,923
------- -------
Diluted earnings per common share:
Income before dilutive effect of certain convertible
securities, extraordinary charge and cumulative effect
of a change in accounting principle ........................... $ 227,592 317,544 $ 0.72 $ 80,609 286,439 $ 0.28
Dilutive effect of certain convertible securities ............... 20,838 49,379 (0.04) 4,878 18,912 --
--------- ------- ------ -------- ------- ------
Income before extraordinary charge and cumulative effect
of a change in accounting principle ........................... 248,430 366,923 0.68 85,487 305,351 0.28
Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- --
Cumulative effect of a change in accounting principle,
net of tax .................................................... 1,036 -- -- -- -- --
--------- ------- ------ -------- ------- ------
Net income ...................................................... $ 248,166 366,923 $ 0.68 $ 85,487 305,351 $ 0.28
========= ======= ====== ======== ======= ======
Unexercised employee stock options to purchase approximately 284.8 and 36.0
thousand shares of the Company's common stock during the six months ended June
30, 2001 and 2000, respectively, were not included in the computation of diluted
shares outstanding because such inclusion would have been anti-dilutive.
15. Commitments and Contingencies
Capital Expenditures -- During the second quarter of 2001, the Company purchased
35 model 7FB and 11 model 7FA gas-fired turbines from GE Power Systems. The
Company expects to take delivery of 5 turbines in 2002, with the remainder of
the contract to be filled by the end of 2005. This brought the total number of
gas-fired and steam turbines on order to 304 with an approximate value of $9
billion.
16. Subsequent Events
PG&E Bankruptcy Proceedings -- 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 Capine'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.
The 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
must be completed within 45 days from the date the California ISO provides
certain critical data for the purpose of developing the factual basis needed to
implement the refund methodology and order refunds. While it is not possible to
predict the amount of any refunds until the hearing takes 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 May 15, 2001, the Company announced that Canada Power Holdings Ltd. had
entered into a letter of intent to acquire and assume operations of two Canadian
power generating facilities from British Columbia-based Westcoast Energy, Inc.
for up to approximately US$250 million, plus the assumption of US$14.6 million
of debt. The Company will gain a 100 percent interest in the 250-megawatt
natural gas-fired Island Cogeneration facility located near Campbell River,
British Columbia on Vancouver Island, and a 50 percent interest in the
50-megawatt Whitby Cogeneration facility located in Whitby, Ontario. The
acquisition is expected to close in the third quarter of 2001 and is subject to
final documentation and various third party and regulatory approvals.
On July 5, 2001, the Company announced an agreement to acquire a 1,200-megawatt
natural gas-fired power plant at Saltend near Hull, Yorkshire, England from
Entergy Wholesale Operations for up to approximately 562.5 million pounds
sterling (approximately US$800 million at current exchange rates). The Saltend
facility, a cogeneration facility, provides electricity and steam for BP
Chemical's Hull Works plant under a 15-year agreement. The balance of the
Saltend facility's electricity output is sold into the deregulated United
Kingdom power market. The acquisition is expected to close in the third quarter
of this year and is subject to third party approvals.
On July 10, 2001, the Company jointly announced with PG&E Corporation's PG&E
National Energy Group the completion of the acquisition of the 500-megawatt
natural gas-fired Otay Mesa Generating Project in San Diego County. The PG&E
National Energy Group developed the combined-cycle project, which was licensed
by the California Energy Commission in April. Construction is expected to begin
later this summer, and with completion scheduled for mid-2003, the project will
be the first new power facility built in San Diego County in 30 years. Under the
terms of the sale, Calpine 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 July 10, 2001, the Company announced the acquisition of a majority interest
of Michael Petroleum Corporation, a Houston, Texas-based natural gas exploration
and development company. These reserves are located exclusively in South Texas.
The assets include total proved reserves of 204 bcfe and currently produce 43
mmcfe/d. In addition, this transaction provides an inventory of high quality,
low risk drilling locations within a 94,000 acreage position in close proximity
to the Magic Valley Generating Station and the Hidalgo Energy Center. The value
of the transaction is approximately $338.5 million, plus the assumption of $44.1
million of debt. The acquisition is expected to close in the third quarter of
2001.
On August 1, 2001, the Company announced an agreement with Edison Mission Energy
for the purchase of the remaining fifty percent equity interest in a
240-megawatt combined-cycle cogeneration facility located in Gordonsville,
Virginia for $35 million. The Gordonsville facility provides electric power and
steam to Virginia Electric and Power Company and the Rapidan Service Authority,
respectively, under long-term contracts that expire in 2024. The acquisition is
expected to close in the third quarter of 2001.
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) changes in government regulations,
including pending changes in California, and anticipated deregulation of the
electric energy industry, (ii) 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,
(iii) cost estimates are preliminary and actual costs may be higher than
estimated, (iv) the assurance that the Company will develop additional plants,
(v) a competitor's development of a lower-cost generating gas-fired power plant,
(vi) the risks associated with marketing and selling power from power plants in
the newly competitive energy market, (vii) the risks associated with marketing
and selling combustion turbine parts and components in the competitive
combustion turbine parts market, (viii) the risks associated with engineering,
designing and manufacturing combustion turbine parts and components, or (ix)
delivery and performance risks associated with combustion turbine parts and
components attributable to production, quality control, suppliers and
transportation. 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.
For example, Pacific Gas and Electric Company ("PG&E"), which is in bankruptcy,
has recently agreed with the Company to assume all of the Company's Qualifying
Facility contracts. 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.
Overview
Calpine is engaged in the development, acquisition, ownership, and operation of
power generation facilities and the sale of electricity and steam in the United
States and Canada. At August 13, 2001, we had interests in 58 operating power
plants representing 9,626 megawatts of net capacity.
On April 3, 2001, we announced that our affiliate, Calpine Power America, L.P.,
was certified as a Retail Energy Provider in the Electric Reliability Council of
Texas ("ERCOT"). This allows us to offer services to a full range of wholesale
and retail customers in Texas. Calpine Power America will sell to large
industrials, in addition to municipalities, cooperatives, and investor-owned
utilities. Additionally, we received an ERCOT certification to be a Qualified
Scheduling Entity ("QSE"). As a QSE, Calpine Power Management, L.P. may act on
behalf of generators and consumers in the region and would be responsible for
scheduling the generation of energy flowing to the electricity grid with the
ERCOT Independent System Operator.
On April 3, 2001, we acquired all of the common shares of WRMS Engineering, Inc.
("WRMS"), a California-based engineering and architectural firm, through a
stock-for-stock exchange in which WRMS shareholders received a total of 151,176
shares of Calpine common stock. The aggregate value of the transaction is
approximately $7.8 million, including the assumed indebtedness of WRMS. WRMS is
expected to provide services to support our c*Power unit, which provides highly
reliable, critical power to industrial and high tech customers.
On April 11, 2001, we acquired the development rights from Enron North America
for the 750-megawatt natural gas-fired Pastoria Energy Center planned for Kern
County, California. The project was licensed by the California Energy Commission
in December 2000. Construction began in June 2001 and commercial operation is
scheduled for the summer of 2003.
On April 17, 2001, we acquired the development rights from Kirkland,
Washington-based National Energy Systems Company for the 248-megawatt natural
gas-fired Goldendale Energy Center planned for Goldendale, Washington. Energy
generated from the Goldendale facility will be sold directly into the Northwest
Power Pool. Construction commenced in April 2001, and energy deliveries are
scheduled to begin July 1, 2002.
On April 17, 2001, we acquired assets of The Bayless Companies and its partners
with reserves located in the western portion of the San Juan Basin in New
Mexico. Currently 35 wells produce approximately 6 million cubic feet equivalent
per day ("mmcfe/d"), 96 percent of which is natural gas.
On April 19, 2001, we announced the purchase of 35 model 7FB and 11 model 7FA
gas-fired turbines from GE Power Systems. We will take delivery of 5 turbines in
2002, with the remainder of the contract to be filled by the end of 2005.
On April 19, 2001, we acquired all of the common shares of Encal Energy Ltd.
("Encal"), 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 of our subsidiary, Calpine Canada
Holdings Ltd. A total of 16,603,633 Calpine common equivalent shares were issued
to Encal shareholders in exchange for their Encal common stock. Each Calpine
common equivalent share is exchangeable for one share of Calpine common stock.
The aggregate value of the transaction is approximately U.S. $1.1 billion,
including the assumed indebtedness of Encal. This acquisition was accounted for
under the pooling-of-interests method. With the addition of Encal's assets,
which currently produce approximately 230 mmcfe per day, net of royalties, our
net production is expected to increase to 390 mmcfe per day in North America,
enough to fuel approximately 2,300 megawatts of our power fleet.
On April 25, 2001, through our wholly owned financing company, Calpine Canada
Energy Finance ULC ("Energy Finance"), we completed a public offering of $1.5
billion of 8 1/2% Senior Notes Due 2008 priced at 99.768%. These senior notes
are fully and unconditionally guaranteed by us.
On April 30, 2001, we completed the sale of $1.0 billion of Zero-Coupon
Convertible Debentures Due 2021 in a private placement under Rule 144A of the
Securities Act of 1933. The securities are convertible into Calpine common
shares at a price of $75.35 at the option of the holder at any time. Holders
have the right to require us to repurchase their debentures in 2002, 2004, 2006,
2008, 2011 and 2016 at a specified price in cash or our common stock at our
option, except in 2016 when the repurchase price must be paid in cash. The
debentures are redeemable at the option of Calpine after 2004 at a specified
price in cash or our common stock. Proceeds from the offering were used to
refinance certain debt, for working capital and for general corporate purposes.
The indenture relating to these securities has not been filed with the
Securities and Exchange Commission at the date of this filing. We will furnish a
copy to the Securities and Exchange Commission upon request.
On May 2, 2001, we jointly announced with Kinder Morgan Energy Partners, L.P.
plans to develop the Sonoran Pipeline, subject to a successful open season and
all other approvals. As proposed, the Sonoran Pipeline will be a 1,160-mile,
high-pressure interstate natural gas pipeline from the San Juan Basin in
northern New Mexico to markets in California. The interstate pipeline will be
evaluated and developed in two phases, which will be subject to the jurisdiction
of the Federal Energy Regulatory Commission ("FERC"). The first phase will run
from the San Juan Basin to the California border with the second phase extending
from the California border to the San Francisco Bay area. The first phase of the
pipeline is expected to be completed in the summer of 2003.
On May 9, 2001, we announced that our emergency energy proposal to the San
Francisco Public Utilities Commission was approved by the San Francisco Board of
Supervisors. Under the terms of this contract, we will guarantee to provide San
Francisco with 50 megawatts of electricity 24 hours-a-day for the next five
years starting July 1, 2001.
On May 15, 2001, we announced that we plan to build, own and operate a
1,030-megawatt natural gas-fired electricity generating facility to be located
in Berrien, Michigan. We entered into an agreement with Boston-based CME North
American Merchant Energy, which had initiated development efforts for the
project and will continue to work with us as the project moves forward. The
Berrien Energy Center is our first Michigan development project and commercial
operation is scheduled to begin in 2004.
On May 15, 2001, we announced that our wholly owned subsidiary, Canada Power
Holdings Ltd., entered into a letter of intent to acquire and assume operations
of two Canadian power generating facilities from British Columbia-based
Westcoast Energy, Inc. for up to approximately US$250 million, plus the
assumption of US$14.6 million of debt. We will own a 100 percent interest in the
250-megawatt natural gas-fired Island Cogeneration facility located near
Campbell River, British Columbia on Vancouver Island, and a 50 percent interest
in the 50-megawatt Whitby Cogeneration facility located in Whitby, Ontario. The
acquisition is expected to close in the third quarter of 2001 and is subject to
final documentation and various third party and regulatory approvals.
At the Annual Meeting of Stockholders on May 17, 2001, the stockholders elected
Ann B. Curtis and Kenneth T. Derr as the Class II Directors, approved the
amendment to the Company's Amended and Restated Certificate of Incorporation to
increase the number of authorized shares of Common Stock from 500,000,000 to
1,000,000,000, and ratified the appointment of Arthur Andersen LLP as
independent accountants for the fiscal year ending December 31, 2001.
On May 23, 2001, we, together with San Francisco-based Bechtel Enterprises
Holdings, Inc., filed an Application For Certification with the California
Energy Commission ("CEC") for the proposed Russell City Energy Center, a
600-megawatt, natural gas-fired, combined-cycle electric generating facility
located in Hayward, California. The filing marks the beginning of an extensive
CEC licensing process required to build and operate an electricity generating
facility in California. The filing included a request for expedited review that
would reduce the licensing review process period from 12 months to 6 months.
Based upon successful licensing of the project, construction could begin in the
summer of 2002, with commercial operation by the summer of 2004. The Russell
City Energy Center would provide electricity for Hayward, western Alameda County
and the San Francisco Peninsula.
On June 7, 2001, we jointly announced with Kinder Morgan Energy Partners, L.P.
that we received significant interest in the proposed Sonoran Pipeline project
during the open seasons that closed on June 1, 2001. More than 1 billion cubic
feet ("Bcf") per day of binding precedent agreements and non-binding expressions
of interest were received for Phase One of Sonoran, and another 1.5 Bcf per day
of non-binding commitments and expressions of interest were received for Phase
Two of the project.
On June 7, 2001, we redeemed all $105 million in aggregate outstanding principal
amount of our 9 1/4% Senior Notes Due 2004 at a redemption price of 100% of the
principal amount plus accrued interest to the redemption date.
On June 8, 2001, we announced plans to build, own and operate a 600-megawatt
electric generating facility to be located in southwestern Riverside County,
California. The proposed Inland Empire Energy Center will feed directly into
Southern California Edison's power grid and is intended to serve the rapidly
growing counties of Riverside and San Bernardino. Construction is scheduled to
begin in mid-2002, with commercial operation targeted for mid-2004.
On June 20, 2001, we jointly announced with Bechtel Enterprises Holdings, Inc.
that the Presiding Members' Proposed Decision, released by the California Energy
Commission on June 18, 2001, recommends that the full five-member CEC approve
the 600-megawatt, gas-fired Metcalf Energy Center. The CEC's final decision is
expected in the third quarter 2001.
On June 28, 2001, we announced that Florida's Power Plant Siting Board granted
final state regulatory approval for the proposed 529-megawatt Osprey Energy
Center, to be located in Auburndale, Florida. We are the first independent power
producer to receive approval of a Site Certification Application for a
large-scale combined-cycle generating facility under Florida's complex Power
Plant Siting Act.
Transactions Announced or Consummated Subsequent to June 30, 2001, and Recent
Developments
On July 2, 2001, we announced commercial operation of our Sutter Energy Center,
located near Yuba City, California. The Sutter Energy Center, the first major
combined-cycle facility built in California in over a decade, is providing 540
megawatts of electricity to California on a 24 hours-a-day, seven days-a-week
availability.
On July 5, 2001, we announced that we had signed a binding agreement to acquire
a 1,200-megawatt natural gas-fired power plant at Saltend near Hull, Yorkshire,
England from Entergy Wholesale Operations for up to approximately 562.5 million
pounds sterling (US$800 million). The Saltend Energy Centre entered commercial
operations in November 2000 and is one of the largest natural gas-fired electric
power generating facilities in England. As a cogeneration facility, Saltend
Energy Centre provides electricity and steam for BP Chemical's 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. The facility incorporates
natural gas-fired combustion turbines in combination with steam turbines to
optimize fuel efficiency.
On July 9, 2001, we announced initial operation of our Los Medanos Energy Center
in Pittsburg, California. This 555-megawatt facility is the second major
combined-cycle facility to be licensed and built in California in over a decade
and will provide electricity on a 24 hours-a-day, 7 days-a-week availability. As
a cogeneration facility, the project also delivers electricity and steam to USS
POSCO for use in industrial processing.
On July 10, 2001, we jointly announced with PG&E Corporation's PG&E National
Energy Group that we had completed the acquisition of the 500-megawatt natural
gas-fired Otay Mesa Generating Project in San Diego County. The PG&E National
Energy Group developed the combined-cycle project, which was licensed by the
California Energy Commission in April. Construction is expected to begin later
this summer, and with completion scheduled for mid-2003, the project will be the
first new power facility built in San Diego County in 30 years. Under the terms
of the sale, we 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 our subsidiary,
Calpine Energy Services, LP ("CES").
On July 10, 2001, we announced the acquisition of a majority interest of Michael
Petroleum Corporation, a Houston, Texas-based natural gas exploration and
development company. These reserves are located exclusively in South Texas. The
assets include total proved reserves of 204 bcfe and currently produce 43
mmcfe/d. In addition, this transaction provides an inventory of high quality,
low risk drilling locations within a 94,000 acreage position in close proximity
to the Magic Valley Generating Station and the Hidalgo Energy Center. The value
of the transaction is approximately $338.5 million plus the assumption of $44.1
million of debt. The acquisition is expected to close in the third quarter of
2001.
On July 11, 2001, we jointly announced with Bechtel Enterprises Holdings, Inc.
that the Application for Certification of the Russell City Energy Center met the
California Energy Commission's data adequacy requirements. The project was also
approved for expedited review, making the 600-megawatt Russell City Energy
Center the first combined-cycle California energy project to meet the CEC's
stringent qualifications for a six-month review.
On July 11, 2001, we announced plans for the 180-megawatt Los Esteros Critical
Energy Facility. Located in San Jose, California, our c*Power program will
supply U.S. Data Port's planned San Jose Internet Campus with highly reliable
critical power and ancillary services. Construction of the facility will be
accelerated so that in advance of the initiation and completion of the U.S. Data
Port project we will be able to provide 180 megawatts of peaking capacity and
energy to the California Department of Water Resources under a power contract
beginning May 1, 2002 and continuing through April 30, 2005.
On July 16, 2001, we announced that Michael Polsky had resigned from the Board
of Directors and as an officer of the Company. On July 17, 2001, we announced
the appointment of Gerald Greenwald to the Board of Directors.
On July 17, 2001, we announced plans to build a 900-megawatt natural gas-fired
facility called the Sherry Energy Center in Wood County, Wisconsin. We entered
into two separate 10-year agreements to supply 225 megawatts and 141 megawatts
of electric capacity and energy from the plant to the Wisconsin Electric Power
Company and the Wisconsin Public Service Corporation, respectively. The
remaining output will be sold to other Wisconsin utilities and wholesale power
purchasers. Construction is expected to begin during the second quarter of 2002,
with commercial operation of the simple-cycle units slated for the second
quarter of 2003, and commercial operation of the combined-cycle plant expected
in the second quarter of 2004.
On July 17, 2001, we signed two 5-year agreements to deliver 1,000 megawatts of
power to Reliant Energy Services, Inc., a unit of Reliant Resources, Inc. The
contracts will begin with the official start date of deregulation in ERCOT,
which is expected to be January 1, 2002. We will serve Reliant's load from our
ERCOT system of natural gas-fired power plants totaling approximately 2,700
megawatts of capacity.
On July 18, 2001, we jointly announced with Shell Energy Services Company
L.L.C., a wholly owned subsidiary of Shell Oil Company, the signing of an
exclusive energy agreement. We will be the exclusive provider of up to 3,000
megawatts of electricity to Shell Energy, a retail electricity provider
participating in the Texas Electric Choice pilot program in the ERCOT. Beginning
January 1, 2002, we will provide capacity, energy, and ancillary services to
Shell for the ERCOT market in accordance with the 5-year full requirements
contract.
On July 19, 2001, we announced a ten-year agreement for the sale of 100
megawatts of power to Excelon Generation's Power Team. This power will be
produced by the Morris Power Plant located just southwest of Chicago, Illinois.
On August 1, 2001, we announced an agreement with Edison Mission Energy for the
purchase of the remaining fifty percent equity interest in a 240-megawatt
combined-cycle cogeneration facility located in Gordonsville, Virginia for $35
million. The Gordonsville facility provides electric power and steam to Virginia
Electric and Power Company and the Rapidan Service Authority, respectively,
under long-term contracts that expire in 2024.
On August 9, 2001, we announced plans to purchase 27 steam turbine generators
from Siemens Westinghouse. We expect turbine deliveries to begin in September
2002, with full inventory in place by February 2005. Combined, the turbines
represent up to 5,400 megawatts of generating capacity.
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 have been
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, 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 are subject
to the retail rate freeze, including PG&E, have faced wholesale prices that far
exceed the retail prices they are permitted to charge. This has led to
significant under-recovery of costs by these utilities. As a consequence, these
utilities have defaulted under a variety of contractual obligations, including
payment obligations to power generators. PG&E has defaulted on payment
obligations to Calpine under Calpine's 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 $266 million in accounts receivable with
PG&E under our QF contracts, plus $69 million in notes receivable not yet due
and payable. As of June 30, 2001, we had recorded $292 million in accounts
receivable and $84 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 Calpine,
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. We cannot predict when the bankruptcy court will confirm a plan of
reorganization for PG&E.
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.
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 agreed to assume
its QF contracts with us in bankruptcy, 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.
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. This contract is contingent upon our
satisfaction, in our sole discretion, that adequate provisions have been made by
DWR to assure us of full payment under the terms of the contract (including, but
not limited to, the terms and conditions of any bonds issued by DWR to provide
funds for payment of its obligations under the contract).
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. Each of these contracts is also contingent upon our satisfaction, in our
sole discretion, that adequate provisions have been made by DWR to assure us of
full payment under the terms of that contract (including, but not limited to,
the terms and conditions of any bonds issued by DWR to provide funds for payment
of its obligations under that contract).
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.
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 must be completed within 45 days from the date the
California ISO provides certain critical data for the purpose of developing the
factual basis needed to implement the refund methodology and order refunds.
While it is not possible to predict the amount of any refunds until the hearing
takes 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.
Selected Operating Information
Set forth below is certain selected operating information for our power plants
and steam fields, for which results are consolidated in our statements of
operations. Results vary for the three and six months ended June 30, 2001,
respectively, as compared to the same periods in 2000, primarily due to the
consolidation of acquisitions, favorable energy pricing, and increased
production. 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.
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2001 2000 2001 2000
---------- ---------- ----------- ----------
Electricity and steam ("E & S") revenues:
Energy (1) ............................... $ 354,366 $ 199,950 $ 806,552 $ 325,329
Capacity ................................. $ 147,064 $ 89,318 $ 245,323 $ 144,802
Thermal and other ........................ $ 32,157 $ 20,738 $ 74,205 $ 34,696
Megawatt hours produced ..................... 7,877,505 4,678,000 15,116,704 9,059,189
Average energy price per megawatt hour ...... $ 44.98 $ 42.74 $ 53.36 $ 35.91
(1) Includes spread on sales of purchased power.
Megawatt hours produced at the power plants increased 68% and 67% for the three
and six months ended June 30, 2001, 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 June 30, 2000.
Results of Operations
Three Months Ended June 30, 2001, Compared to Three Months Ended June 30, 2000
Revenue -- Total revenue increased to $1,612.9 million for the three months
ended June 30, 2001, compared to $417.2 million for the same period in 2000.
Electric generation and marketing revenue increased 268% to $1,257.3
million in 2001 compared to $341.6 million in 2000. Approximately $192.9
million of the $915.7 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 June 30, 2001, includes the
consolidated results of fourteen additional facilities that we acquired or
completed construction on subsequent to June 30, 2000. Our power marketing
revenue (sales of purchased power) grew by $654.2 million due to increased
price hedging and optimization activity during the three months ended June
30, 2001. We also recognized $68.4 million in mark-to-market gains on power
derivatives.
Oil and gas production and marketing revenue increased to $343.0 million in
2001 compared to $69.7 million in 2000. The majority of the increase is due
to marketing activities relating to purchased gas sold to third parties in
hedging, balancing and related transactions. Additionally, approximately
$54.4 million of the variance relates to increased production and commodity
prices from sales to third parties from our reserves in Canada and in the
United States.
Income from unconsolidated investments in power projects decreased to $1.6
million in 2001 compared to $4.8 million during 2000. The variance is
primarily due to the contractual reduction in distributions from the Sumas
Power Plant of approximately $2.6 million.
Other revenue increased to $10.9 million in 2001 compared to $1.1 million
in 2000. This increase is due primarily to $4.8 million recognized in 2001
from our custom turbine parts manufacturing subsidiary, Power Systems Mfg.,
LLC, which was acquired in December 2000, and $2.8 million in interest
income on loans to power projects.
Cost of revenue -- Cost of revenue increased to $1,308.6 million in 2001
compared to $270.5 million in 2000. Approximately $623.7 million of the $1,038.1
million increase relates to the cost of power purchased by our energy services
organization. Similarly, oil and gas production and marketing expense grew by
$220.5 million, largely due to $218.3 million of expense for the cost of gas
purchased by the energy services organization, compared to $7.5 million in the
second quarter of 2000. Fuel expense increased 120%, from $104.0 million in 2000
to $228.4 million in 2001, due to a 68% increase in megawatt hours generated and
increased fuel price. Depreciation expense increased by 42%, from $50.7 million
in the second quarter of 2000 to $72.1 million in the second quarter of 2001,
due to fourteen additional power facilities in consolidated operations at June
30, 2001, as compared to the same period in 2000, and due to $14.4 million in
higher depreciation and depletion in our oil and gas operating subsidiaries.
Operating lease expense increased by $16.8 million due to leases entered into or
acquired in connection with our Pasadena, Tiverton, Rumford, and KIAC
facilities, all of which were either entered into during or after the second
quarter of 2000.
General and administrative expense -- General and administrative expense
increased 173% to $50.5 million for the three months ended June 30, 2001, as
compared to $18.5 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.
Nonrecurring merger costs -- We incurred approximately $35.6 million in the
three months ended June 30, 2001, in connection with the merger with Encal
Energy Limited 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 138% to $43.3 million for the
three months ended June 30, 2001, from $18.2 million for the same period in
2000. Interest expense increased primarily due to the issuances of $1.15 billion
of Senior Notes Due 2011 in February 2001 and of $1.5 billion of Energy Finance
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 69% to $15.4 million for the three months ended June 30,
2001, compared to $9.1 million for the corresponding months in 2000. The
increase is attributable to the issuance of additional trust preferred
securities in August 2000.
Interest income -- Interest income increased to $20.5 million for the three
months ended June 30, 2001, compared to $5.6 million for the same period in
2000. This increase is due to the significantly higher cash balances that we
have maintained, primarily from senior notes issuances and the issuance of our
convertible securities in April 2001.
Other income -- Other income increased to $3.3 million in 2001 from $(0.2)
million in 2000 primarily due to foreign currency gains relating to Encal debt
that was repaid during the quarter.
Provision for income taxes -- The effective income tax rate was approximately
39.1% and 41.1% for the three months ended June 30, 2001 and 2000, respectively.
The decrease in rates was due to the lower contribution of Canadian operations
(which are subject to higher statutory tax rates) due partially to the
recognition of nonrecurring merger costs.
Extraordinary charge, net -- The $1.3 million charge relating to write off of
unamortized deferred financing costs was a result of the repayment of $105
million 9 1/4% Senior Notes Due 2004.
Six Months Ended June 30, 2001, Compared to Six Months Ended June 30, 2000
Revenue -- Total revenue increased to $2,952.6 million for the six months ended
June 30, 2001, compared to $702.4 million for the same period in 2000.
Electric generation and marketing revenue increased to $2,307.4 million in
2001 compared to $547.7 million in 2000. Approximately $594.3 million of
the $1,759.7 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 June 30, 2001, includes the consolidated
results of fourteen additional facilities that we acquired or completed
construction on subsequent to June 30, 2000. Our power marketing activities
contributed an additional $1,095.7 million due to increased price hedging
and optimization activity during the six months ended June 30, 2001. We
also recognized $69.7 million in mark-to-market gains on power derivatives.
Oil and gas production and marketing revenue increased to $628.9 million in
2001 compared to $136.6 million in 2000. Approximately $339.5 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 $152.7 million of the variance relates to
increased production and commodity prices in sales to third parties from
reserves acquired in Canada and in the United States.
Income from unconsolidated investments in power projects decreased to $2.2
million in 2001 compared to $14.6 million during 2000. The variance is
primarily due to the contractual reduction in distributions from the Sumas
Power Plant of approximately $9.7 million.
Other revenue increased to $14.2 million in 2001 compared to $3.4 million
in 2000. This increase is due primarily to $6.4 million recognized in 2001
from our custom turbine parts manufacturing subsidiary, Power Systems Mfg.,
LLC, and a $2.8 million increase in interest income on loans to power
projects.
Cost of revenue -- Cost of revenue increased to $2,372.8 million in 2001
compared to $484.6 million in 2000. Approximately $1,068.7 million of the
$1,888.2 million increase relates to the cost of power purchased by our energy
services organization. Similarly, oil and gas production and marketing expense
grew by $343.0 million, largely due to a $321.7 million increase in expense for
the cost of gas purchased and resold by the energy services organization. Fuel
expense increased 173%, from $177.7 million in 2000 to $485.4 million in 2001,
due to a 67% increase in megawatt hours generated and a significant increase in
fuel price. Depreciation expense increased by 51%, from $95.8 million in the
first six months of 2000 to $144.2 million in the first six months of 2001, due
to additional power facilities in operation in 2001 and due to $30.2 million in
higher depreciation and depletion in our oil and gas operating subsidiaries.
Operating lease expense increased by $34.3 million due to leases entered into or
acquired in connection with our Pasadena, Tiverton, Rumford, and KIAC facilities
during and subsequent to the period ended June 30, 2000.
General and administrative expense -- General and administrative expense
increased 202% to $86.6 million for the six months ended June 30, 2001, as
compared to $28.7 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.
Nonrecurring merger costs -- We incurred approximately $41.6 million in the six
months ended June 30, 2001, in connection with the merger with Encal Energy
Limited 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 58% to $63.3 million for the six
months ended June 30, 2001, from $40.0 million for the same period in 2000.
Interest expense increased primarily due to the issuances of $1.15 billion of
Senior Notes Due 2011 in February 2001 and of $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 90% to $30.6 million for the first six months in 2001
compared to $16.1 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 on the January 2000 offering and
the subsequent exercise of the purchasers' option to purchase additional
securities.
Interest income -- Interest income increased to $39.9 million for the six months
ended June 30, 2001, compared to $13.2 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 second quarter of 2001.
Other income -- Other income increased to $9.0 million in 2001 from $0.4 million
in 2000 primarily due to a gain on the sale of our interests in the Elwood
development project and the Bayonne facility and related contingent income
recognized as earned thereafter.
Provision for income taxes -- The effective income tax rate was approximately
41.1% and 41.2% for the six months ended June 30, 2001 and 2000, respectively.
Extraordinary charge, net -- The $1.3 million charge was a result of writing off
unamortized deferred financing costs related to the repayment of $105 million 9
1/4% Senior Notes Due 2004.
Cumulative effect of a change in accounting principle -- The $1.0 million of
additional income, net of tax, is due to the adoption 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").
Liquidity and Capital Resources
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; and proceeds from project
financing. We 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.
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 uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations, risk management and power marketing, which we believe provides 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 allows
us to achieve significant operating synergies and efficiencies in fuel
procurement, power marketing and operation and maintenance.
At August 13, 2001, we had 27 projects under construction, representing an
additional 14,932 megawatts of net capacity. Included in these 27 projects are 4
project expansions, representing 735 megawatts of net capacity. We have also
announced plans to develop 29 additional power generation projects, representing
a net capacity of 16,618 megawatts. Included in these 29 development projects
are 5 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 81 power plants with a net capacity of 24,558 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.
Risk Factors
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 Federal Energy
Regulatory Commission.
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 agreed to assume
its QF contracts with us in bankruptcy, 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.
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.
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 must be completed within 45 days from the date the
California ISO provides certain critical data for the purpose of developing the
factual basis needed to implement the refund methodology and order refunds.
While it is not possible to predict the amount of any refunds until the hearing
takes 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 June 30, 2001, we had short-term investments of
$740.8 million. These short-term investments consist of highly liquid
investments with maturities 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 -- 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 June 30, 2001 (dollars in thousands):
Notional Weighted
Principal Average Fair
Maturity Date Amount Interest Rate Market Value
------------- --------- ------------- ------------
2001................... $ 71,000 7.4% $ (72)
2007................... 38,150 8.0 (3,907)
2007................... 38,150 8.0 (3,889)
2007................... 29,757 7.9 (3,146)
2007................... 29,757 7.9 (3,131)
2009................... 15,000 6.9 (709)
2011................... 55,742 6.9 (2,611)
2012................... 120,078 6.5 (3,273)
2014................... 72,334 6.7 (2,815)
2015................... 22,500 7.0 (1,278)
2018................... 17,500 7.0 (1,055)
--------- ---- ---------
Total......... $ 509,968 7.1% $ (25,886)
========= ==== =========
Energy price fluctuations -- We enter into derivative commodity instruments to
reduce our exposure to the impact of price fluctuations, primarily electricity
and natural gas prices. All transactions are subject to our risk management
policy which prohibits positions that exceed production capacity and fuel
requirements. 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 June 30, 2001
Electricity................. $ 595,850 $ (204,773)
Natural gas................. (294,840) (105,763)
---------- ----------
Total................... $ 301,010 $ (310,536)
=========== ==========
Derivative commodity instruments included in the table are those included in
Note 3 to the 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 six months
ended June 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 forward sales
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.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in ITEM 2.
PART II. OTHER INFORMATION
ITEM 2. Change in Securities and Use of Proceeds.
On April 30, 2001, we completed the sale of $1.0 billion of Zero-Coupon
Convertible Debentures Due 2021 in a private placement under Rule 144A of the
Securities Act of 1933. The securities are convertible into Calpine common
shares at a price of $75.35 at the option of the holder at any time. Holders
have the right to require us to repurchase their debentures in 2002, 2004, 2006,
2008, 2011 and 2016 at a specified price in cash or Calpine common stock at our
option, except in 2016 when the repurchase price must be paid in cash. The
debentures are redeemable at the option of Calpine after 2004 at a specified
price in cash or Calpine common stock.
ITEM 4. Submission of Matters to a Vote of Security Holders.
Our Annual Meeting of Stockholders was held on May 17, 2001, (the "Annual
Meeting") in Boston, Massachusetts. At the Annual Meeting, the stockholders
voted on the following matters: (i) the proposal to elect two Class II Directors
to the Board of Directors for a term of three years expiring in 2004, (ii) the
proposal to amend the Company's Amended and Restated Certificate of
Incorporation to increase the number of authorized shares of Common Stock, par
value $.001 per share ("Common Stock"), from 500,000,000 to 1,000,000,000; and
(iii) the proposal to ratify the appointment of Arthur Andersen LLP as
independent accountants for the Company for the fiscal year ending December 31,
2001. The stockholders elected management's nominees as the Class II Directors
in an uncontested election, approved the amendment to the Company's Amended and
Restated Certificate of Incorporation to increase the number of authorized
shares of Common Stock from 500,000,000 to 1,000,000,000, and ratified the
appointment of independent accountants by the following votes, respectively:
(i) Election of Ann B. Curtis and Kenneth T. Derr as Class II Directors
for a three-year term expiring 2004, 250,888,564 FOR and 2,555,356
ABSTAIN,
(ii) Amendment to the Company's Amended and Restated Certificate of
Incorporation to increase the authorized shares of Common Stock from
500,000,000 to 1,000,000,000, 226,837,920 FOR, 25,790,692 AGAINST, and
815,308 ABSTAIN, and
(iii)Ratification of the appointment of Arthur Andersen LLP as independent
accountants for the fiscal year ending December 31, 2001, 240,859,017
FOR, 11,784,745 AGAINST, and 800,158 ABSTAIN.
The three-year terms of Class III and Class I Directors continued after the
Annual Meeting and will expire in 2002 and 2003, respectively. The Class III
Directors include Peter Cartwright, Michael P. Polsky, and Susan C. Schwab. The
Class I Directors are Jeffrey E. Garten, George J. Stathakis, and John O.
Wilson.
Subsequent to the Annual Meeting, on July 16, 2001, we announced that Michael
Polsky had resigned from the Board of Directors. 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.
*2.2 Amending Agreement to the Combination Agreement, dated as of
March 16, 2001, between Calpine Corporation and Encal Energy
Ltd. (a)
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 (b)
*3.2 Certificate of Correction of Calpine Corporation (c)
*3.3 Certificate of Amendment of Amended and Restated Certificate
of Incorporation of Calpine Corporation (d)
*3.4 Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation (c)
*3.5 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (c)
*3.6 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (d)
3.7 Certificate of Designation of Special Voting Preferred Stock
of Calpine Corporation
*3.8 Amended and Restated By-laws of Calpine Corporation (e)
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 (f)
*4.4 First Supplemental Indenture dated as of September 28, 2000,
between Calpine Corporation and Wilmington Trust Company, as
Trustee (g)
*4.5 Indenture dated as of April 25, 2001, between Calpine Canada
Energy Finance ULC and Wilmington Trust Company, as Trustee (h)
*4.6 Guarantee Agreement dated as of April 25, 2001, by Calpine
Corporation as guarantor of debt securities of Calpine Canada
Energy Finance ULC (h)
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 (i)
- ------------
* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3/A (File No. 333-56712).
(b) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3 (File No. 333-40652).
(c) 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.
(d) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3 (File No. 333-66078).
(e) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-1 (File No. 333-07497).
(f) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3/A (File No. 333-72583).
(g) 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).
(h) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3/A (File No. 333-57338).
(i) 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.
(b) Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the quarter ended
June 30, 2001:
Date of Report Date Filed Item Reported
-------------- -------------- -------------
April 9, 2001 April 10, 2001 5
April 19, 2001 April 19, 2001 2, 7
April 26, 2001 April 30, 2001 5, 7
June 26, 2001 June 26, 2001 5
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: August 14, 2001
---------------------------------
Ann B. Curtis
Executive Vice President
(Chief Financial Officer)
By: /s/ Charles B. Clark, Jr. Date: August 14, 2001
---------------------------------
Charles B. Clark, Jr.
Vice President and Corporate Controller
(Chief Accounting Officer)