UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): December 31, 2004
CALPINE CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
(State or Other Jurisdiction of Incorporation)
Commission file number: 001-12079
I.R.S. Employer Identification No. 77-0212977
50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115
(Address of principal executive offices and telephone number)
Check the appropriate box below if the Form 8-K filing is intended to
simultaneously satisfy the filing obligation of the registrant under any of the
following provisions:
[ ] Written communications pursuant to Rule 425 under the Securities Act
(17 CFR 230.425)
[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act
(17 CFR 240.14a-12)
[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the
Exchange Act (17 CFR 240.14d-2(b))
[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the
Exchange Act (17 CFR 240.13e-4(c))
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ITEM 8.01 -- OTHER EVENTS
In the three months ended June 30, 2005, Calpine Corporation ("Calpine" or
the "Company")committed to a plan to divest its remaining oil and gas assets and
the Saltend Energy Centre. This Form 8-K is being filed to revise information
that was previously reported in Calpine's Annual Report on Form 10-K for the
year ended December 31, 2004 (the "2004 Form 10-K"), which was filed on March
31, 2005, to reflect these businesses as discontinued operations in accordance
with Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." The Company designated these
businesses as "held for sale" in the three months ended June 30, 2005, (these
businesses were subsequently disposed of in the third quarter of 2005).
Only the following sections of the 2004 Form 10-K have been revised:
o Item 6. Selected Financial Data
o Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
o Item 8. Financial Statements and Supplementary Data
No other sections have been changed. While the revisions affect the
classification between income from continuing operations and income from
discontinued operations, none of the revisions (which are discussed in more
detail in the accompanying consolidated financial statements in exhibit 99.3),
affect net income for any of the three years in the period ended December 31,
2004.
PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS FORM 8-K, INCLUDING THE
FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT OTHER EVENTS
OCCURRING AFTER THE INITIAL FILING DATE OF THE COMPANY'S 2004 FORM 10-K. SUCH
EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR QUARTERLY REPORTS ON
FORM 10-Q FOR THE PERIODS ENDED MARCH 31, 2005, AND JUNE 30, 2005, AND THE
EVENTS DESCRIBED IN THE COMPANY'S CURRENT REPORTS ON FORM 8-K FILED SUBSEQUENT
TO MARCH 31, 2005.
ITEM 9.01 - FINANCIAL STATEMENTS AND EXHIBITS
(a) Financial Statements of Businesses Acquired.
Not Applicable
(b) Pro Forma Financial Information.
Not Applicable
(c) Exhibits.
23.1 Consent of PricewaterhouseCoopers LLP, Independent Registered Public
Accounting Firm.
23.2 Consent of Deloitte & Touche LLP, Independent Registered Public
Accounting Firm.
23.3 Consent of Netherland, Sewell & Associates, Inc., Independent
Engineer.
23.4 Consent of Gilbert Laustsen Jung Associates Ltd., Independent
Engineer.
99.1 Item 6 of Form 10-K for the fiscal year ended December 31, 2004:
Selected Financial Data.
99.2 Item 7 of Form 10-K for the fiscal year ended December 31, 2004:
Management's Discussion and Analysis of Financial Condition and
Results of Operations.
99.3 Item 8 of Form 10-K for the fiscal year ended December 31, 2004:
Financial Statements and Supplementary Data.
-2-
EXHIBIT 99.1
Item 6. Selected Financial Data
Selected Consolidated Financial Data
Years Ended December 31,
---------------------------------------------------------------------
2004 2003 2002 2001 2000
------------ ------------ ------------ ------------ ------------
(In thousands, except earnings per share)
Statement of Operations data:
Total revenue............................................... $ 8,780,855 $ 8,524,198 $ 7,107,809 $ 6,386,249 $ 2,161,280
============ ============ ============ ============ ============
Income before discontinued operations and cumulative
effect of a change in accounting principle................ $ (442,669) $ (26,101) $ 2,391 $ 468,579 $ 286,205
Discontinued operations, net of tax......................... 200,208 127,180 116,227 153,877 82,879
Cumulative effect of a change in accounting principle....... -- 180,943 -- 1,036 --
------------ ------------ ------------ ------------ ------------
Net income.................................................. $ (242,461) $ 282,022 $ 118,618 $ 623,492 $ 369,084
============ ============ ============ ============ ============
Basic earnings per common share:
Income before discontinued operations and cumulative
effect of a change in accounting principle............... $ (1.03) $ (0.07) $ 0.01 $ 1.54 $ 1.02
Discontinued operations, net of tax....................... 0.47 0.33 0.32 0.51 0.29
Cumulative effect of a change in accounting principle,
net of tax............................................... -- 0.46 -- -- --
------------ ------------ ------------ ------------ ------------
Net income................................................ $ (0.56) $ 0.72 $ 0.33 $ 2.05 $ 1.31
============ ============ ============ ============ ============
Diluted earnings per common share:
Income before discontinued operations and cumulative
effect of a change in accounting principle............... $ (1.03) $ (0.07) $ 0.01 $ 1.38 $ 0.93
Discontinued operations, net of tax provision............. 0.47 0.32 0.32 0.42 0.25
Cumulative effect of a change in accounting principle,
net of tax............................................... -- 0.46 -- -- --
------------ ------------ ------------ ------------ ------------
Net income................................................ $ (0.56) $ 0.71 $ 0.33 $ 1.80 $ 1.18
============ ============ ============ ============ ============
Balance Sheet data:
Total assets................................................ $ 27,216,088 $ 27,303,932 $ 23,226,992 $ 21,937,227 $ 10,610,232
Short-term debt and capital lease obligations............... 1,033,956 349,128 1,651,448 903,307 64,525
Long-term debt and capital lease obligations................ 16,940,809 17,328,181 12,462,290 12,490,175 5,018,044
Company-obligated mandatorily redeemable convertible
preferred securities of subsidiary trusts (1)............. $ -- $ -- $ 1,123,969 $ 1,122,924 $ 1,122,390
- ------------
<FN>
(1) Included in long-term debt as of December 31, 2003 and 2004. See Note 12 of
the Notes to Consolidated Financial Statements for more information.
</FN>
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Years Ended December 31,
---------------------------------------------------------------------
2004 2003 2002 2001 2000
------------ ------------ ------------ ------------ ------------
(In thousands)
Reconciliation of GAAP cash provided from operating
activities to EBITDA, as adjusted (1):
Cash provided by operating activities....................... $ 9,895 $ 290,559 $ 1,068,466 $ 423,569 $ 875,751
Less: Changes in operating assets and liabilities,
excluding the effects of acquisitions (2)................. (137,614) (609,840) 480,193 (359,640) 277,696
Less: Additional adjustments to reconcile net income to
net cash provided by operating activities, net (2)........ 389,970 618,377 469,655 159,717 228,971
------------ ------------ ------------ ------------ ------------
GAAP net income (loss)...................................... $ (242,461) $ 282,022 $ 118,618 $ 623,492 $ 369,084
(Income) loss from unconsolidated investments in power
projects and oil and gas properties....................... 14,088 (75,724) (16,552) (16,946) (28,796)
Distributions from unconsolidated investments in power
projects and oil and gas properties....................... 29,869 141,627 14,117 5,983 29,979
------------ ------------ ------------ ------------ ------------
Adjusted net income (loss)................................ $ (198,504) $ 347,925 $ 116,183 $ 612,529 $ 370,267
Interest expense............................................ 1,116,800 716,124 417,368 187,581 72,665
1/3 of operating lease expense.............................. 35,295 37,357 37,007 33,173 21,154
Distributions on trust preferred securities................. -- 46,610 62,632 62,412 45,076
Provision (benefit) for income taxes........................ (247,690) (34,387) 21,882 253,534 180,696
Depreciation, depletion and amortization expense............ 528,346 460,999 320,826 211,618 139,964
Interest expense, provision for income taxes and
depreciation from discontinued operations................. 419,638 224,679 205,438 251,988 193,910
------------ ------------ ------------ ------------ ------------
EBITDA, as adjusted (1)..................................... $ 1,653,885 $ 1,799,307 $ 1,181,336 $ 1,612,835 $ 1,023,732
============ ============ ============ ============ ============
- ------------
<FN>
(1) This non-GAAP measure is presented not as a measure of operating results,
but rather as a measure of our ability to service debt and to raise
additional funds. It should not be construed as an alternative to either
(i) income from operations or (ii) cash flows from operating activities. It
is defined as net income less income from unconsolidated investments, plus
cash received from unconsolidated investments, plus provision for tax, plus
interest expense (including distributions on trust preferred securities and
one-third of operating lease expense, which is management's estimate of the
component of operating lease expense that constitutes interest expense,)
plus depreciation, depletion and amortization. The interest, tax and
depreciation and amortization components of discontinued operations are
added back in calculating EBITDA, as adjusted.
For the year ended December 31, 2004, EBITDA, as adjusted, includes a
$246.9 million gain from the repurchase of debt, offset by approximately
$223.4 million of certain charges, consisting primarily of foreign currency
transaction losses, write-off of deferred financing costs not related to
the bonds repurchased, equipment cancellation and impairment costs, certain
mark-to-market activity, and minority interest expense, some of which
required, or will require cash settlement.
For the year ended December 31, 2003, EBITDA, as adjusted, includes a
$180.9 million (net of tax) gain from the cumulative effect of a change in
accounting principle and a $278.6 million gain from the repurchase of debt,
offset by approximately $273.0 million of certain charges, consisting
primarily of foreign currency transaction losses, equipment cancellation
and impairment costs, certain mark-to-market activity, and minority
interest expense, some of which required, or will require cash settlement.
EBITDA, as adjusted for the year ended December 31, 2002, includes a
non-cash equipment cancellation charge of $404.7 million, a $118.0 million
gain on the repurchase of debt, and approximately $55.0 million of certain
charges, some of which required, or will require cash settlement.
(2) See the Consolidated Statements of Cash Flows for further detail of these
items.
</FN>
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Selected Operating Information
Years Ended December 31,
---------------------------------------------------------------------
2004 2003 2002 2001 2000
------------ ------------ ------------ ------------ ------------
(Dollars in thousands, except pricing data)
Power Plants(1):
Electricity and steam ("E&S") revenues:
Energy.................................................... $ 3,861,223 $ 3,081,850 $ 2,075,457 $ 1,606,228 $ 1,220,684
Capacity.................................................. 1,036,445 992,410 781,127 525,174 376,085
Thermal and other......................................... 400,152 319,201 175,147 155,478 99,297
------------ ------------ ------------ ------------ ------------
Subtotal................................................. $ 5,297,820 $ 4,393,461 $ 3,031,731 $ 2,286,880 $ 1,696,066
Spread on sales of purchased power(2)....................... 165,730 29,003 527,544 349,601 11,262
------------ ------------ ------------ ------------ ------------
Adjusted E&S revenues....................................... $ 5,463,550 $ 4,422,464 $ 3,559,275 $ 2,636,481 $ 1,707,328
MWh produced................................................ 87,750 73,553 64,865 40,215 22,750
All-in electricity price per MWh generated.................. $ 62.26 $ 60.13 $ 54.87 $ 65.56 $ 75.05
- ------------
<FN>
(1) From continuing operations only. Discontinued operations are excluded.
(2) From hedging, balancing and optimization activities related to our
generating assets.
</FN>
Set forth above is certain selected operating information for our power
plants for which results are consolidated in our statements of operations.
Electricity revenue is composed of fixed capacity payments, which are not
related to production, and variable energy payments, which are related to
production. Capacity revenues include, 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 steam
sales and other thermal revenue.
Set forth below is a table summarizing the dollar amounts and percentages
of our total revenue for the years ended December 31, 2004, 2003, and 2002, that
represent purchased power and purchased gas sales for hedging and optimization
and the costs we incurred to purchase the power and gas that we resold during
these periods (in thousands, except percentage data):
Years Ended December 31,
------------------------------------------------
2004 2003 2002
------------- ------------- --------------
Total revenue................................................................... $ 8,780,855 $ 8,524,198 $ 7,107,809
Sales of purchased power for hedging and optimization(1)........................ 1,647,992 2,712,291 3,145,989
As a percentage of total revenue................................................ 18.8% 31.8% 44.3%
Sale of purchased gas for hedging and optimization.............................. 1,728,301 1,320,902 870,466
As a percentage of total revenue................................................ 19.7% 15.5% 12.2%
Total cost of revenue ("COR")................................................... 8,410,101 7,916,836 6,158,705
Purchased power expense for hedging and optimization(1)......................... 1,482,262 2,683,288 2,618,445
As a percentage of total COR.................................................... 17.6% 33.9% 42.5%
Purchased gas expense for hedging and optimization.............................. 1,716,714 1,279,568 821,065
As a percentage of total COR.................................................... 20.4% 16.2% 13.3%
- ------------
<FN>
(1) On October 1, 2003, we adopted on a prospective basis EITF Issue No. 03-11
and netted certain purchases of power against sales of purchased power. See
Note 2 of the Notes to Consolidated Financial Statements for a discussion
of our application of EITF Issue No. 03-11.
</FN>
The primary reasons for the significant levels of these sales and costs of
revenue items include: (a) significant levels of hedging, balancing and
optimization activities by our CES risk management organization; (b)
particularly volatile markets for electricity and natural gas, which prompted us
to frequently adjust our hedge positions by buying power and gas and reselling
it; (c) the accounting requirements under Staff Accounting Bulletin ("SAB") No.
101, "Revenue Recognition in Financial Statements," and EITF Issue No. 99-19,
"Reporting Revenue Gross as a Principal versus Net as an Agent," under which we
show most of our hedging contracts on a gross basis (as opposed to netting sales
and cost of revenue); and (d) rules in effect associated with the NEPOOL market
in New England, which require that all power generated in NEPOOL be sold
directly to the ISO in that market; we then buy from the ISO to serve our
customer contracts. GAAP required us to account for this activity, which applies
to three of our merchant generating facilities, as the aggregate of two distinct
-5-
sales and one purchase until our prospective adoption of EITF Issue No. 03-11 on
October 1, 2003. This gross basis presentation increased revenues but not gross
profit. The table below details the financial extent of our transactions with
NEPOOL for financial periods prior to the adoption of EITF Issue No. 03-11. Our
entrance into the NEPOOL market began with our acquisition of the Dighton,
Tiverton and Rumford facilities on December 15, 2000.
Nine Months
Ended Year Ended
September 30, December 31,
2003 2002
----------- -----------
(In thousands)
Sales to NEPOOL from power we generated........... $ 258,945 $ 294,634
Sales to NEPOOL from hedging and other activity... 117,345 106,861
----------- -----------
Total sales to NEPOOL........................... $ 376,290 $ 401,495
Total purchases from NEPOOL....................... $ 310,025 $ 360,113
(The statement of operations data information and the balance sheet data
information contained in the Selected Financial Data is derived from the audited
Consolidated Financial Statements of Calpine Corporation and Subsidiaries. See
the Notes to the Consolidated Financial Statements and Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Results of Operations" for additional information.)
-6-
EXHIBIT 99.2
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Overview
Our core business and primary source of revenue is the generation and
delivery of electric power. We provide power to our U.S. and Canadian customers
through the integrated development, construction or acquisition, and operation
of efficient and environmentally friendly electric power plants fueled primarily
by natural gas and, to a much lesser degree, by geothermal resources. We protect
and enhance the value of our electric assets and gas positions with a
sophisticated risk management organization. We also protect our power generation
assets and control certain of our costs by producing certain of the combustion
turbine replacement parts that we use at our power plants, and we generate
revenue by providing combustion turbine parts to third parties. Finally, we
offer services to third parties to capture value in the skills we have honed in
building, commissioning, repairing and operating power plants.
Prior to the sale of the Saltend Energy Centre in July 2005 we also
generated electricity in the United Kingdom, and prior to the sale of our
remaining oil and gas assets in July 2005, we owned and produced natural gas and
to a lesser extent oil, which we used primarily to lower our costs of power
production and to provide a natural hedge of fuel costs for a portion of our
electric power plants. See Note 10 of the Notes to Consolidated Financial
Statements).
Our key opportunities and challenges include:
o preserving and enhancing our liquidity while spark spreads (the
differential between power revenues and fuel costs) are depressed,
o selectively adding new load-serving entities and power users to our
customer list as we increase our power contract portfolio,
o continuing to add value through prudent risk management and
optimization activities, and
o lowering our costs of production through various efficiency programs.
Since the latter half of 2001, there has been a significant contraction in
the availability of capital for participants in the energy sector. This has been
due to a range of factors, including uncertainty arising from the collapse of
Enron and a near-term surplus supply of electric generating capacity in certain
market areas. These factors coupled with a three-year period of decreased spark
spreads have adversely impacted our liquidity and earnings. While we have
generally been able to continue to access the capital and bank credit markets on
terms acceptable to us, we recognize that the terms of financing available to us
in the future may not be attractive. To protect against this possibility and due
to current market conditions, we scaled back our capital expenditure program to
enable us to conserve our available capital resources. In 2004 we completed
several strategic financings including the refinancing of our CalGen, formerly
Calpine Construction Finance Company II, LLC ("CCFC II"), revolving construction
facility indebtedness of approximately $2.5 billion, and the issuance of $785
million of 9 5/8% First Priority Senior Secured Notes Due 2014 and $736 million
of Contingent Convertible Notes Due 2014 ("2014 Convertible Notes"), all of
which are further discussed in Note 17 of the Notes to Consolidated Financial
Statements. Debt maturities are relatively modest in 2005 and 2006 as shown in
Note 11 of the Notes to Consolidated Financial Statements, but we face several
challenges over the next two to three years as our cash requirements (including
our refinancing obligations) are expected to exceed our unrestricted cash on
hand and cash from operations. Accordingly, we have in place a liquidity-
enhancing program which includes possible sales or monetizations of certain of
our assets.
Set forth below are the Results of Operations for the years ending December
31, 2004, 2003, and 2002 (in millions, except for unit pricing information,
percentages and MW volumes; in the comparative tables below, increases in
revenue/income or decreases in expense (favorable variances) are shown without
brackets. Decreases in revenue/income or increases in expense (unfavorable
variances) are shown with brackets). Prior year amounts have been reclassified
for discontinued operations.
-7-
Results of Operations
Year Ended December 31, 2004, Compared to Year Ended December 31, 2003
Revenue
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Total revenue............................................................. $ 8,780.9 $ 8,524.2 $ 256.7 3.0%
The increase in total revenue is explained by category below.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Electricity and steam revenue............................................. $ 5,297.8 $ 4,393.5 $ 904.3 20.6%
Transmission sales revenue................................................ 20.0 15.3 4.7 30.7%
Sales of purchased power for hedging and optimization..................... 1,648.0 2,712.3 (1,064.3) (39.2)%
----------- ----------- ------------
Total electric generation and marketing revenue......................... $ 6,965.8 $ 7,121.1 $ (155.3) (2.2)%
=========== =========== ============
Electricity and steam revenue increased as we completed construction and
brought into operation five new baseload power plants and two project expansions
in 2004. Average MW in operation of our consolidated plants increased by 24% to
23,490 MW while generation increased by 19%. The increase in generation lagged
behind the increase in average MW in operation as our baseload capacity factor
dropped to 48% in 2004 from 51% in 2003 primarily due to the increased
occurrence of unattractive off-peak market spark spreads in certain areas due in
part to mild weather, which caused us to cycle off certain of our merchants
plants without contracts in off peak hours, and also due to oversupply
conditions which are expected to gradually work off over the next several years.
Average realized electricity prices, before the effects of hedging, balancing
and optimization, increased to $60.37/MWh in 2004 from $59.73/MWh in 2003.
Transmission sales revenue increased in 2004 due to the increased emphasis
in optimizing our portfolio through the resale of our underutilized transmission
positions in the short- to mid-term markets.
Sales of purchased power for hedging and optimization decreased during 2004
due primarily to netting of approximately $1,676.0 of sales of purchased power
with purchased power expense in 2004 compared to $256.6 in 2003 (netting in 2003
occurred only in the fourth quarter) in connection with the adoption of EITF
Issue No. 03-11 on a prospective basis in the fourth quarter of 2003, partly
offset by higher volumes and higher realized prices on hedging, balancing and
optimization activities. Without this netting, sales of purchased power would
have increased by $355.1, or 12.0%.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Oil and gas sales......................................................... $ 4.1 $ 2.4 $ 1.7 70.8%
Sales of purchased gas for hedging and optimization....................... 1,728.3 1,320.9 407.4 30.8%
----------- ----------- ------------
Total oil and gas production and marketing revenue...................... $ 1,732.4 $ 1,323.3 $ 409.1 30.9%
=========== =========== ============
In the three months ended June 30, 2005, the Company committed to a plan to
divest its remaining oil and gas assets and reclassified the related operations
to discontinued operations. These oil and gas assets were subsequently disposed
of in July 2005. The remaining activities in continuing operations related to
gas pipeline activities and activities associated with certain minor assets sold
in 2004 and prior years that did not meet the criteria for reclassification to
discontinued operations at the times of sale. See Note 10 of the Notes to
Consolidated Financial Statements for more information.
Sales of purchased gas for hedging and optimization increased during 2004
due primarily to higher volumes and higher prices of natural gas as compared to
the same period in 2003.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Realized gain on power and gas mark-to-market transactions, net........... $ 48.1 $ 24.3 $ 23.8 97.9%
Unrealized (loss) on power and gas mark-to-market transactions, net....... (34.7) (50.7) 16.0 31.6%
-8-
----------- ----------- ------------
Mark-to-market activities, net.......................................... $ 13.4 $ (26.4) $ 39.8 150.8%
=========== =========== ============
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
including positions accounted for as trading under EITF Issue No. 02-03 and
other mark-to-market activities. These commodity positions represent a small
portion of our overall commodity contract position. Realized revenue represents
the portion of contracts actually settled and is offset by a corresponding
change in unrealized gains or losses as unrealized derivative values are
converted from unrealized forward positions to cash at settlement. Unrealized
gains and losses include the change in fair value of open contracts as well as
the ineffective portion of our cash flow hedges.
During 2004, we recognized a net gain from mark-to-market activities
compared to net losses in 2003. In 2004 our exposure to mark-to-market earnings
volatility declined commensurate with a corresponding decline in the volume of
open commodity positions underlying the exposure. As a result, the magnitude of
earnings volatility attributable to changes in prices declined. We recorded a
hedge ineffectiveness gain of approximately $7.6 in 2004 versus a hedge
ineffectiveness loss of $1.8 for the corresponding period in 2003. Additionally,
during 2004 we recorded gains of $9.2 on a mark-to-market derivative contract
that was terminated during 2004 versus a mark-to-market loss of $15.5 on the
same contract in 2003.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Other revenue............................................................. $ 69.2 $ 106.2 $ (37.0) (34.8)%
Other revenue decreased during 2004 primarily due to a one-time pre-tax
gain of $67.3 realized during 2003, in connection with our settlement with
Enron, principally related to the final negotiated settlement of claims and
amounts owed under terminated commodity contracts. The decrease in 2004 was
partially offset by increases of $13.3 and $12.0 from combustion turbine parts
sales and repair and maintenance services performed by TTS and construction
management and operating services performed by CPSI, respectively.
Cost of Revenue
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Cost of revenue........................................................... $ 8,410.1 $ 7,916.8 $ (493.3) (6.2)%
The increase in total cost of revenue is explained by category below.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Plant operating expense................................................... $ 745.7 $ 616.4 $ (129.3) (21.0)%
Royalty expense........................................................... 28.7 24.9 (3.8) (15.3)%
Transmission purchase expense............................................. 74.8 34.7 (40.1) (115.6)%
Purchased power expense for hedging and optimization...................... 1,482.3 2,683.3 1,201.0 44.8%
----------- ----------- ------------
Total electric generation and marketing expense......................... $ 2,331.5 $ 3,359.3 $ 1,027.8 30.6%
=========== =========== ============
Plant operating expense increased as five new baseload power plants and two
expansion projects were completed during 2004, and due to higher major
maintenance expense on existing plants as many of our newer power plants
performed their initial major maintenance work. In North America, 25 of our
gas-fired plants performed major maintenance work, an increase of 67% over the
number of plants that did so in 2003. In addition, during 2004 we incurred $54.3
for equipment failure costs compared to $11.0 in 2003.
Transmission purchase expense increased primarily due to additional power
plants achieving commercial operation in 2004.
Approximately 76% of the royalty expense for 2004 vs. 78% for 2003 is
attributable to royalties paid to geothermal property owners at The Geysers,
mostly as a percentage of geothermal electricity revenues. The increase in
royalty expense in 2004 was due primarily to a $2.5 increase in royalties at The
Geysers, and the remainder was due to an increase in the accrual of contingent
purchase price payments to the previous owners of the Texas City and Clear Lake
Power Plants based on a percentage of gross revenues at these two plants.
-9-
Purchased power expense for hedging and optimization decreased during 2004
as compared to 2003 due primarily to netting of approximately $1,676.0 of
purchased power expense against sales of purchased power in 2004 compared to
$256.6 in 2003, in connection with the adoption of EITF Issue No. 03-11 in the
fourth quarter of 2003, partly offset by higher volumes and higher realized
prices on hedging, balancing and optimization activities. Without this netting,
purchased power expense would have increased by $218.4 or 7.4%.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Oil and gas operating expense............................................. $ 8.6 $ 20.0 $ 11.4 57.0%
Purchased gas expense for hedging and optimization........................ 1,716.7 1,279.6 (437.1) (34.2)%
----------- ----------- ------------
Total oil and gas operating and marketing expense..................... $ 1,725.3 $ 1,299.6 $ (425.7) (32.8)%
=========== =========== ============
In the three months ended June 30, 2005, the Company committed to a plan to
divest its remaining oil and gas assets and reclassified the related operations
to discontinued operations. These oil and gas assets were subsequently disposed
of in July 2005. The remaining activities in continuing operations related to
gas pipeline activities and activities associated with certain minor oil and gas
assets sold in 2004 and prior years that did not meet the criteria for
reclassification to discontinued operations at the times of sale. See Note 10 of
the Notes to Consolidated Financial Statements for more information.
Purchased gas expense for hedging and optimization increased during 2004
due to higher volumes and higher prices for gas in 2004.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Fuel expense
Cost of oil and gas burned by power plants................................ $ 3,694.5 $ 2,715.1 $ (979.4) (36.1)%
Recognized (gain) on gas hedges........................................... (1.5) (11.6) (10.1) (87.1)%
----------- ----------- -----------
Total fuel expense...................................................... $ 3,693.0 $ 2,703.5 $ (989.5) (36.6)%
=========== =========== ===========
Cost of oil and gas burned by power plants increased during 2004 as
compared to 2003 due to a 19.9% increase in gas consumption as we increased our
MW production and higher prices for gas excluding the effects of hedging,
balancing and optimization.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Depreciation, depletion and amortization expense.......................... $ 463.7 $ 400.1 $ (63.6) (15.9)%
Depreciation, depletion and amortization expense increased in 2004
primarily due to additional power plants achieving commercial operation
subsequent to 2003.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Operating lease expense................................................... $ 105.9 $ 112.1 $ 6.2 5.5%
Operating lease expense decreased during 2004 as compared to 2003 primarily
because the King City lease terms were restructured and the lease began to be
accounted for as a capital lease. As a result, we ceased incurring operating
lease expense on that lease and instead began to incur depreciation and interest
expense.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Other cost of revenue.................................................... $ 90.7 $ 42.3 $ (48.4) (114.4)%
Other cost of revenue increased during 2004 as compared to 2003 primarily
due to $29.0 of amortization expense in 2004 versus $10.6 in 2003 incurred from
the adoption of DIG Issue No. C20. In the fourth quarter of 2003, we recorded a
pre-tax mark-to-market gain of $293.4 as a cumulative effect of a change in
-10-
accounting principle. This gain is amortized as expense over the respective
lives of the two power sales contracts from which the mark-to-market gains
arose. We also incurred $11.3 of additional expense from TTS in 2004, as the
entity had a full year of activity (we acquired TTS in late February of 2003).
Additionally, CPSI cost of revenue increased $10.8 in 2004 compared to 2003 due
to an increase in services contract activity.
(Income)/Expense
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
(Income) loss from unconsolidated investments in power projects and oil
and gas properties...................................................... $ 14.1 $ (75.7) $ (89.8) (118.6)%
The reduction in income was primarily due to a non-recurring $52.8 gain in
2003, representing our 50% share, on the termination of the tolling arrangement
with Aquila Merchant Services, Inc. ("AMS") at the Acadia Energy Center and a
loss of $11.6 realized in 2004, representing our share of a jury award to
International Paper Company ("IP") in a litigation relating to Androscoggin
Energy LLC ("AELLC") together with a $5 impairment charge recorded when
Androscoggin filed for bankruptcy protection in the fourth quarter of 2004.
Also, we did not have any income on our Gordonsville investment in 2004,
compared to $12.0 in 2003, as we sold our interest in this facility in November
2003. For further information, see Note 7 of the Notes to Consolidated Financial
Statements.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Equipment cancellation and impairment cost................................ $ 42.4 $ 64.4 $ 22.0 34.2%
In 2004, the pre-tax equipment cancellation and impairment charge was
primarily a result of charges of $33.7 related to cancellation costs of six heat
recovery steam generators ("HRSG") orders and HRSG component parts cancellations
and impairments. In 2003 the pre-tax equipment cancellation and impairment
charge was primarily a result of cancellation costs related to three turbines
and three HRSGs and impairment charges related to four turbines.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Long-term service agreement cancellation charge........................... $ 11.3 $ 16.4 $ 5.1 31.1%
Long-term service agreement ("LTSA") cancellation charges decreased
primarily due to $14.1 in cancellation costs incurred in 2003 associated with
LTSAs with General Electric related to our Rumford, Tiverton and Westbrook
facilities. In 2004 the decrease was offset by a $7.7 adjustment as a result of
settlement negotiations related to the cancellation of LTSAs with
Siemens-Westinghouse Power Corporation at our Hermiston, Ontelaunee, South Point
and Sutter facilities and a $3.8 adjustment as a result of LTSA cancellation
settlement negotiations with General Electric regarding cancellation charges at
our Los Medanos facility.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Project development expense............................................... $ 24.4 $ 21.8 $ (2.6) (11.9)%
Project development expense increased during 2004 primarily due to higher
costs associated with cancelled projects, and due to costs incurred in 2004 on
oil and gas storage, pipeline and liquid natural gas projects.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Research and development expense.......................................... $ 18.4 $ 10.6 $ (7.8) (73.6)%
Research and development expense increased in 2004 as compared to 2003
primarily due to increased personnel expense related to gas turbine component
research and development programs at our PSM subsidiary.
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2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Sales, general and administrative expense................................. $ 222.0 $ 204.1 $ (17.9) (8.8)%
Sales, general and administrative expense increased in 2004 due primarily
to an increase of $20.4 of Sarbanes-Oxley 404 internal control project costs.
Sales, general and administrative expense expressed per MWh of generation
decreased to $2.53/MWh in 2004 from $2.77/MWh in 2003, due to a 19% increase in
MWh generated as more plants entered commercial operation.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Interest expense.......................................................... $ 1,116.8 $ 716.1 $ (400.7) (56.0)%
Interest expense increased as a result of higher average debt balances,
higher average interest rates and lower capitalization of interest expense.
Interest capitalized decreased from $412.2 in 2003 to $375.3 in 2004 as a result
of new plants that entered commercial operations (at which point capitalization
of interest expense ceases). We expect that the amount of interest capitalized
will continue to decrease in future periods as our plants in construction are
completed. Additionally during 2004, (i) interest expense related to our senior
notes and term loans increased $125.8; (ii) interest expense related to our
CalGen financing was responsible for an increase of $113.7; (iii) interest
expense related to our notes payable and borrowings under lines of credit
increased $40.0; (iv) interest expense related to our CCFC I financing increased
$26.1; and (v) interest expense related to our preferred interests increased
$28.7. The majority of the remaining increase relates to an increase in average
indebtedness due primarily to the deconsolidation of our three Calpine Capital
Trust subsidiaries (the "Trusts") which issued the HIGH TIDES I, II and III and
recording of debt to the Trusts due to the adoption of Financial Accounting
Standards Board ("FASB") Interpretation No. ("FIN") 46, "Consolidation of
Variable Interest Entities, an interpretation of ARB 51" ("FIN 46")
prospectively on October 1, 2003 (see Note 2 of the Notes to Consolidated
Financial Statements for a discussion of our adoption of FIN 46). Interest
expense related to the notes payable to the Trusts during 2004 was $58.6. The
distributions were excluded from the interest expense caption on our
Consolidated Statements of Operations through the nine months ended September
30, 2003, while $15.1 of interest expense related to the Trusts was recorded for
the quarter ending December 31, 2003. The HIGH TIDES I and II and the related
notes payable to the Trusts were redeemed in October 2004.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Distributions on trust preferred securities............................... $ -- $ 46.6 $ 46.6 100.0%
As discussed above, as a result of the deconsolidation of the Trusts upon
adoption of FIN 46 as of October 1, 2003, the distributions paid on the HIGH
TIDES I, II and III during 2004 were no longer recorded on our books and were
replaced prospectively by interest expense on our debt to the Trusts.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Interest (income)......................................................... $ (54.8) $ (39.2) $ 15.6 39.8%
The increase in interest (income) in 2004 is due to an increase in cash and
cash equivalents and restricted cash balances during the year. Additionally, we
generated interest income on the repurchases of our HIGH TIDES I, II and III.
For further information, see Note 3 of the Notes to Consolidated Financial
Statements.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Minority interest expense................................................. $ 34.7 $ 27.3 $ (7.4) (27.1)%
Minority interest expense increased during 2004 as compared to 2003 due to
our reduced ownership percentage in the Calpine Power Limited Partnership
("CPLP") following the sale of our interest in the Calpine Power Income Fund
("CPIF") which owns 70% of CPLP. Our 30% interest is subordinate to CPIF's
interest.
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2004 2003 $ Change % Change
----------- ----------- ------------ ------------
(Income) from the repurchase of various issuances of debt................. $ (246.9) $ (278.6) $ (31.7) (11.4)%
Income from repurchases of various issuances of debt during 2004 decreased
by $31.7 from the corresponding period primarily as a result of lower face
amounts of debt repurchased in open market and privately negotiated
transactions.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Other (income), net....................................................... $ (121.3) $ (46.0) $ 75.3 163.7%
Other income increased in 2004 as compared to 2003 primarily due to (a)
pre-tax income in 2004 in the amount of $171.5 associated with the restructuring
of power purchase agreements for our Newark and Parlin power plants and the sale
of Utility Contract Funding II, LLC, net of transaction costs and the write-off
of unamortized deferred financing costs, (b) $16.4 pre-tax gain from the
restructuring of a long-term gas supply contract net of transaction costs and
(c) $12.3 pre-tax gain from the King City restructuring transaction related to
the sale of our debt securities that had served as collateral under the King
City lease, net of transaction costs. In addition, during 2004, foreign currency
transaction losses totaled $41.6, compared to losses of $34.5 in the
corresponding period in 2003. See further discussion of our currency transaction
losses under "Financial Market Risks".
In 2003, we recorded a gain of $62.2 on the sale of oil and gas properties
and a gain of $57.0 from a contract termination of the RockGen facility.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Provision (benefit) for income taxes...................................... $ (247.7) $ (34.4) $ 213.3 620.1%
For 2004, the effective rate was 35.9% as compared to 56.8% for 2003. This
effective rate variance is due to the inclusion of certain permanent items in
the calculation of the effective rate, which are fixed in amount and have a
significant effect on the effective tax rates depending on the materiality of
such items to taxable income.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Discontinued operations, net of tax....................................... $ 200.2 $ 127.2 $ (73.0) (57.4)%
The 2004 discontinued operations activity includes the operational
reclassification to discontinued operations related to the second quarter 2005
commitment to a plan of divestiture of our remaining oil and gas assets in the
U.S. and of our Saltend Energy Centre, the effects of the 2004 sale of our 50%
interest in the Lost Pines 1 Power Project, the 2004 sale of the oil and gas
reserves in the Colorado Piceance Basin and New Mexico San Juan Basin and the
remaining natural gas reserves and petroleum assets in Canada, all of which
resulted in a gain on sale, pre-tax, of $239.6. The 2003 discontinued operations
activity includes the operational reclassification to discontinued operations
related to the 2005 commitment to a plan of divestiture of our remaining oil and
gas assets in the U.S. and of our Saltend Energy Center, the 2004 sales of oil
and gas assets in the U.S. and Canada, the 2004 sale of our 50% of interest in
the Lost Pines 1 Power Project, and the 2003 sale of our specialty data center
engineering business. For more information about discontinued operations, see
Note 10 of the Notes to Consolidated Financial Statements.
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Cumulative effect of a change in accounting principle, net of tax......... $ -- $ 180.9 $ (180.9) (100.0)%
The 2003 gain from the cumulative effect of a change in accounting
principle included three items: (1) a gain of $181.9, net of tax effect, from
the adoption of DIG Issue No. C20; (2) a loss of $1.5 associated with the
adoption of FIN 46, as revised ("FIN 46-R") and the deconsolidation of the
-13-
Trusts which issued the HIGH TIDES. The loss of $1.5 represents the reversal of
a gain, net of tax effect, recognized prior to the adoption of FIN 46-R on our
repurchase of $37.5 of the value of HIGH TIDES by issuing shares of our common
stock valued at $35.0; and (3) a gain of $0.5, net of tax effect, from the
adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" ("SFAS
No. 143").
Net Income (Loss)
2004 2003 $ Change % Change
----------- ----------- ------------ ------------
Net income (loss)......................................................... $ (242.5) $ 282.0 $ (524.5) (186.0)%
Throughout 2004 we continued to focus on opportunities to add value by
adding to and increasing the performance of our power plant portfolio. We added
3,655 MW to our fleet by completing construction on five power plants and two
expansion projects at existing plants. Five of these seven facilities have much
of their output under long-term contracts. In March 2004 we acquired the 570 MW
Brazos Valley Power Plant. Currently our fleet includes 91 power plants in
operation, totaling 25,449 MW.
We generated 87.8 million MWh in 2004, which equated to a baseload capacity
factor of 47.8%, and realized an average spark spread of $20.10/MWh. In 2003 we
generated 73.6 million MWh, which equated to a capacity factor of 50.9%, and
realized an average spark spread of $23.10/MWh.
Gross profit decreased by $236.6, or 39%, to $370.8 in 2004, primarily due
to: (i) non-recurring other revenue of $67.3 recognized in 2003 from the
settlement of contract disputes with, and claims against, Enron; (ii) the
recording in 2004 of approximately $54.3 for equipment failure costs within
plant operating expense, compared to $11.0 in 2003; (iii) the amortization of
$29.0 in 2004 of the DIG Issue No. C20 gain recorded in the fourth quarter of
2003 due to the cumulative effect of a change in accounting principle; and (iv)
soft market fundamentals, which caused total spark spread, despite an increase
of $65.2, or 4%, to not increase commensurate with additional plant operating
expense, transmission purchase expense and depreciation costs associated with
new power plants coming on-line.
During 2004, financial results were also affected by a $400.7 increase in
interest expense and distributions on our debt, as compared to the same period
in 2003. This occurred as a result of higher debt balances, higher average
interest rates and lower capitalization of interest as new plants entered
commercial operation. Prior year results benefited from recording $52.8 (in
income from unconsolidated investments in power projects) due to the termination
of a power purchase agreement by the Acadia joint venture.
Other income increased by $75.3 to $121.2 during 2004, as compared to 2003,
primarily due to: (i) pre-tax income in the amount of $171.5, net of transaction
costs and the write-off of unamortized deferred financing costs, associated with
the restructuring of power purchase agreements for our Newark and Parlin power
plants and the sale of an entity holding a power purchase agreement; (ii) a
$16.4 pre-tax gain from the restructuring of a long-term supply contract net of
transaction costs; and (iii) a $12.3 pre-tax gain from the King City
restructuring transaction related to the sale of our debt securities that had
served as collateral under the King City lease, net of transaction costs. In
2003 we recorded a gain of $62.2 on the sale of oil and gas properties and a
gain of $57.0 from a contract termination at our RockGen facility. See further
discussion of our currency transaction losses under "Financial Market Risks."
In 2004, we recorded a charge of $42.4 for equipment cancellation costs,
primarily related to cancellation of HRSG orders on two of our development
projects. In 2003 there were $64.4 in equipment cancellation charges. Also
during 2004 foreign currency transaction losses were $41.6 compared to losses of
$34.5 in the corresponding period in 2003. We recognized gains totaling $246.9
on repurchases of debt in 2004 compared to $278.6 in 2003 and loss before
discontinued operations and cumulative effect of a change in accounting
principle was $442.7 in 2004.
Discontinued operations, net of tax increased by $73.0 in 2004, compared to
2003, as a result of the sale of our Canadian, and certain of our U.S. oil and
gas assets during the third quarter of 2004 and the sale of our interest in the
Lost Pines facility in the first quarter of 2004. During the year ended December
31, 2004, we recorded $202.1 million in impairment charges related to reduced
proved reserve projections based on the year end independent engineers report,
which is included in discontinued operations in the Consolidated Statement of
Operations. Prior to the commitment to a plan of divestiture of our remaining
oil & gas assets during the three months ended June 30, 2005, this impairment
charge was included in gross profit. These impairments are discussed further in
Note 4 of the Notes to Consolidated Financial Statements.
-14-
Year Ended December 31, 2003, Compared to Year Ended December 31, 2002
Revenue
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Total revenue............................................................. $ 8,524.2 $ 7,107.8 $ 1,416.4 19.9%
The increase in total revenue is explained by category below.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Electricity and steam revenue............................................. $ 4,393.5 $ 3,031.7 $ 1,361.8 44.9%
Transmission sales revenue................................................ 15.3 -- 15.3 100.0%
Sales of purchased power for hedging and optimization..................... 2,712.3 3,146.0 (433.7) (13.8)%
----------- ----------- ------------
Total electric generation and marketing revenue......................... $ 7,121.1 $ 6,177.7 $ 943.4 15.3%
=========== =========== ============
Electricity and steam revenue increased as we completed construction and
brought into operation five new baseload power plants, seven new peaker
facilities and three project expansions in 2003. Average MW in operation of our
consolidated plants increased by 44% to 18,892 MW while generation increased by
13%. The increase in generation lagged behind the increase in average MW in
operation as our baseload capacity factor dropped to 51% in 2003 from 64% in
2002 primarily due to the increased occurrence of unattractive off-peak market
spark spreads in certain areas reflecting oversupply conditions which are
expected to gradually work off over the next several years (this caused us to
cycle off certain of our merchant plants without contracts in off-peak hours)
and to a lesser extent due to unscheduled outages caused by equipment problems
at certain of our plants in the first half of 2003. Average realized electricity
prices, before the effects of hedging, balancing and optimization, increased to
$59.73/MWh in 2003 from $46.74/MWh in 2002.
We generated transmission sales revenue in 2003 due to the resale of some
of our underutilized positions in the short- to mid-term markets.
Sales of purchased power for hedging and optimization decreased during
2003, due primarily to adoption of EITF Issue No. 03-11 and lower realized
prices on term power hedges.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Oil and gas sales......................................................... $ 2.4 $ 27.4 $ (25.0) (91.2)%
Sales of purchased gas for hedging and optimization....................... 1,320.9 870.5 450.4 51.7%
----------- ----------- ------------
Total oil and gas production and marketing revenue........................ $ 1,323.3 $ 897.9 $ 425.4 47.4%
=========== =========== ============
In the three months ended June 30, 2005, the Company committed to a plan to
divest its remaining oil and gas assets and reclassified the related operations
to discontinued operations. These oil and gas assts were subsequently disposed
of in July 2005. The remaining activities in continuing operations related to
gas pipeline activities and activities associated with certain minor assets sold
in 2003 and prior years that did not meet the criteria for reclassification to
discontinued operations at the times of sale. See Note 10 of the Notes to
Consolidated Financial Statements for more information.
Sales of purchased gas for hedging and optimization increased during 2003
due to higher prices for natural gas.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Realized gain on power and gas transactions, net.......................... $ 24.3 $ 26.1 $ (1.8) (6.9)%
Unrealized loss on power and gas transactions, net........................ (50.7) (4.6) (46.1) (1,002.2)%
----------- ----------- ------------
Mark-to-market activities, net............................................ $ (26.4) $ 21.5 $ (47.9) (222.8)%
=========== =========== ============
Realized revenue on power and gas mark-to-market activity represents the
portion of mark-to-market contracts actually settled.
-15-
Mark-to-market activities, which are shown on a net basis, result from
general market price movements against our open commodity derivative positions,
including positions accounted for as trading under EITF Issue No. 02-03, and
other mark-to-market activities. These commodity positions represent a small
portion of our overall commodity contract position. Realized revenue represents
the portion of contracts actually settled, while unrealized revenue represents
changes in the fair value of open contracts, and the ineffective portion of cash
flow hedges. The decrease in mark-to-market activities revenue in 2003 is due
primarily to a $27.3 reduction in value of option contracts associated with a
spark spread protection arrangement for the CCFC I financing and a decline in
the value of a long-term spark spread option contract accounted for on a
mark-to-market basis under SFAS No. 133.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Other revenue............................................................. $ 106.2 $ 10.7 $ 95.5 892.5%
Other revenue increased during 2003 primarily due to $67.3 recorded in
connection with our settlement with Enron, primarily related to the termination
of commodity contracts following the Enron bankruptcy. We also realized $23.6 of
revenue from TTS, which we acquired in late February 2003. PSM revenues
increased $6.2 in 2003 as compared to 2002.
Cost of Revenue
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Total cost of revenue..................................................... $ 7,916.8 $ 6,158.7 $ (1,758.1) (28.5)%
The increase in total cost of revenue is explained by category below.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Plant operating expense................................................... $ 616.4 $ 483.2 $ (133.2) (27.6)%
Royalty expense........................................................... 24.9 17.6 (7.3) (41.5)%
Transmission purchase expense............................................. 34.7 15.3 (19.4) (126.8)%
Purchased power expense for hedging and optimization...................... 2,683.3 2,618.5 (64.8) (2.5)%
----------- ----------- ------------
Total electric generation and marketing expense........................... $ 3,359.3 $ 3,134.6 $ (224.7) (7.2)%
=========== =========== ============
Plant operating expense increased due to five new baseload power plants,
seven new peaker facilities and three expansion projects completed during 2003.
Additionally, we experienced higher transmission expenses and higher maintenance
expense as several newer plants underwent their first scheduled hot gas path
overhauls which generally first occur after a plant has been in operation for
three years.
Transmission purchase expense increased as additional plants were brought
on line in 2003.
Royalty expense increased primarily due to the accrual of $5.3 in 2003 vs.
$0 in 2002 for payments to the previous owner of the Texas City and Clear Lake
Power Plants based on a percentage of gross revenues at these two natural
gas-fired plants. Additionally, royalties increased by $2.0 due to an increase
in electric revenues at The Geysers geothermal plants, where we pay royalties to
geothermal property owners, mostly as a percentage of geothermal electricity
revenues. Approximately 78% of the royalty expense for 2003 is attributable to
such geothermal royalties.
The increase in purchased power expense for hedging and optimization was
due primarily to increased spot market costs to purchase power for hedging and
optimization activities partially offset by netting in the fourth quarter of
2003 due to the adoption of EITF Issue No. 03-11.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Oil and gas operating expense............................................. $ 20.0 $ 26.5 $ 6.5 24.5%
Purchased gas expense for hedging and optimization........................ 1,279.6 821.1 (458.5) (55.8)%
----------- ----------- ------------
Total oil and gas operating and marketing expense......................... $ 1,299.6 $ 847.6 $ (452.0) (53.3)%
=========== =========== ============
-16-
In the three months ended June 30, 2005, the Company committed to a plan to
divest its remaining oil and gas assets and reclassified the related operations
to discontinued operations. These oil and gas assts were subsequently disposed
of in July 2005. The remaining activities in continuing operations related to
gas pipeline activities and activities associated with certain minor oil and gas
assets sold in 2003 and prior years that did not meet the criteria for
reclassification to discontinued operations at the times of sale. See Note 10 of
the Note to Consolidated Financial Statements for more information.
Purchased gas expense for hedging and optimization increased during 2003
due to higher prices for gas in 2003.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Fuel expense
Cost of oil and gas burned by power plants................................ $ 2,715.1 $ 1,625.2 $ (1,089.9) (67.1)%
Recognized (gain) loss on gas hedges...................................... (11.6) 133.0 144.6 108.7%
----------- ----------- ------------
Total fuel expense...................................................... $ 2,703.5 $ 1,758.2 $ (945.3) (53.8)%
=========== =========== ============
Fuel expense increased in 2003, due to a 15% increase in gas-fired MWh
generated and 40% higher prices excluding the effects of hedging, balancing and
optimization.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Depreciation, depletion and amortization expense.......................... $ 400.1 $ 300.0 $ (100.1) (33.4)%
Depreciation, depletion and amortization expense increased in 2003
primarily due to additional power plants achieving commercial operation
subsequent to 2002.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Operating lease expense................................................... $ 112.1 $ 111.0 $ (1.1) (1.0)%
Operating lease expense was flat as the number of operating leases did not
change in 2003 as compared to 2002.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Other cost of revenue..................................................... $ 42.3 $ 7.3 $ (35.0) (479.5)%
Approximately half of this increase is due to $17.3 of TTS expense. TTS was
acquired in late February 2003 so there is no comparable expense in the prior
period. Additionally, PSM expense increased $9.0 in 2003 as compared to 2002 due
primarily to an increase in sales.
(Income)/Expenses
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
(Income) from unconsolidated investments in power projects and oil and
gas properties.......................................................... $ (75.7) $ (16.6) $ 59.1 356.0%
The increase in income is primarily due to a $52.8 gain recognized on the
termination of the tolling agreement with AMS on the Acadia Energy Center (see
Note 7 of the Notes to Consolidated Financial Statements). Additionally, we
realized a pre-tax gain of $7.1 from the sale of our interest in the
Gordonsville Energy Center to Dominion Virginia Power.
-17-
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Equipment cancellation and impairment cost................................ $ 64.4 $ 404.7 $ 340.3 84.1%
In 2003, the pre-tax equipment cancellation and impairment charge was
primarily a result of cancellation costs related to three turbines and three
HRSGs and impairment charges related to four turbines. The pre-tax charge of
$404.7 in 2002 was the result of turbine and other equipment order cancellation
charges and related write-offs as a result of our scale-back in construction and
development activities. For further information, see Note 25 of the Notes to
Consolidated Financial Statements.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Long-term service agreement cancellation charges.......................... $ 16.4 $ -- $ (16.4) (100.0)%
Of the $16.4 in charges incurred in 2003, $14.1 occurred as a result of the
cancellation of LTSAs with General Electric related to our Rumford, Tiverton and
Westbrook facilities. The other $2.3 occurred as a result of the cancellation of
LTSAs with Siemens-Westinghouse Power Corporation related to our Sutter, South
Point, Hermiston and Ontelaunee facilities.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Project development expense............................................... $ 21.8 $ 67.0 $ 45.2 67.5%
Project development expense decreased as we placed certain existing
development projects on hold and scaled back new development activity.
Additionally, write-offs of terminated and suspended development projects
decreased to $3.7 in 2003 from $34.8 in 2002.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Research and development expense.......................................... $ 10.6 $ 10.0 $ (0.6) (6.0)%
The modest increase in research and development is attributed to increased
personnel expenses related to research and development programs at our PSM
subsidiary.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Sales, general and administrative expense................................. $ 204.1 $ 173.3 $ (30.8) (17.8)%
Sales, general and administrative expense increased due to $10.7 of
stock-based compensation expense associated with our adoption of SFAS No. 123,
"Accounting for Stock-Based Compensation," effective January 1, 2003, on a
prospective basis while $7.1 of the increase is attributable to the acquisition
of TTS in late February 2003. Other increases include $7.3 in insurance costs
and a write-off of excess office space. Sales, general and administrative
expense expressed per MWh of generation increased to $2.77/MWh in 2003 from
$2.67/MWh in 2002, due to a lower average capacity factor in 2003.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Interest expense.......................................................... $ 716.1 $ 417.4 $ (298.7) (71.6)%
Interest expense increased primarily due to the new plants entering
commercial operations (at which point capitalization of interest expense
ceases). Interest capitalized decreased from $489.2 for the year ended December
31, 2002, to $412.2 for the year ended December 31, 2003. We expect that
interest expense will continue to increase and the amount of interest
capitalized will decrease in future periods as our plants in construction are
completed, and, to a lesser extent, as a result of suspension of certain of our
development projects and suspension of capitalization of interest thereon. The
-18-
remaining increase relates to an increase in average indebtedness, an increase
in the amortization of terminated interest rate swaps and the recording of
interest expense on debt to the three Trusts due to the adoption of FIN 46-R
prospectively on October 1, 2003. See Note 2 of the Notes to Consolidated
Financial Statements for a discussion of our adoption of FIN 46-R.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Distributions on trust preferred securities............................... $ 46.6 $ 62.6 $ 16.0 25.6%
As a result of the deconsolidation of the Trusts upon adoption of FIN 46-R
as of October 1, 2003, the distributions paid on the HIGH TIDES during the
fourth quarter of 2003 were no longer recorded on our books and were replaced by
interest expense on our debt to the Trusts, thus explaining the decrease in
distributions on the HIGH TIDES in 2003.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Interest (income)......................................................... $ (39.2) $ (42.2) $ (3.0) (7.1)%
The decrease is primarily due to lower cash balances and lower interest
rates in 2003.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Minority interest expense................................................. $ 27.3 $ 2.7 $ (24.6) (911.1)%
The increase is primarily due to an increase of $24.4 of minority interest
expense associated with CPIF, which had an initial public offering in August
2002 to fund its interest in CPLP. During 2003 as a result of a secondary
offering of Calpine's interests in CPIF, we decreased our ownership interests in
CPLP in February 2003 to 30%, thus increasing minority interest expense.
Additionally, prior to fourth quarter of 2003, we presented minority interest
expense related to CPIF net of taxes, but we reclassed $13.4 of tax benefit from
minority interest expense to tax expense in the fourth quarter of 2003, thus
increasing minority interest expense by that amount.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
(Income) from repurchase of various issuances of debt..................... $ (278.6) $ -- $ 278.6 100.0%
The 2003 pre-tax gain of $278.6 was recorded in connection with the
repurchase of various issuances of debt at a discount. In 2002 the primary
contribution was a gain of $114.8 from the receipt of Senior Notes, which were
trading at a discount to face value, as partial consideration for British
Columbia oil and gas asset sales.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Other (income), net....................................................... $ (46.0) $ (154.2) $ (108.2) (70.2)%
Other income during 2003 is comprised primarily of gains of $62.2 on the
sale of oil and gas assets to the CNGT and $57.0 from the termination of a power
contract at our RockGen Energy Center. This income was offset primarily by $34.5
of foreign exchange transaction losses and $13.4 of letter of credit fees. The
foreign exchange transaction losses recognized into income were mainly due to a
strong Canadian dollar during 2003. In 2002 the primary contribution to other
income was a $41.5 gain on the termination of a power sales agreement. See
"Financial Market Risks" for a further discussion of our currency transaction
losses.
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2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Provision (benefit) for income taxes...................................... $ (34.4) $ 21.9 $ 56.3 257.1%
During 2003, the effective tax rate was 56.8% compared to 90.1% in 2002.
This effective rate variance is due to the inclusion of certain permanent items
in the calculation of the effective rate, which are fixed in amount and have a
significant effect on the effective tax rates depending on the materiality of
such items to taxable income.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Discontinued operations, net of tax....................................... $ 127.2 $ 116.2 $ (11.0) (9.5)%
The 2003 discontinued operations activity included the effects of the 2005
commitment to a plan of divestiture of the Saltend Energy Centre and the
remaining oil and gas assets in the U.S., the 2004 sale of oil and gas assets in
the U.S. and Canada, the 2004 sale of the Lost Pines 1 Power Project (in which
we held a 50% undivided interest), and the 2003 sale of the specialty data
center engineering business. The 2002 discontinued operations activity included,
in addition to all of the 2003 discontinued operations, the sales of DePere
Energy Center, Drakes Bay Field, British Columbia and Medicine River oil and gas
assets, all of which were completed by December 31, 2002; therefore, their
results were not included in the 2003 activity. For more information about
discontinued operations, see Note 10 of the Notes to Consolidated Financial
Statements.
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Cumulative effect of a change in accounting principle, net of tax......... $ 180.9 $ -- $ 180.9 100.0%
The gain from the cumulative effect of a change in accounting principle
includes three items: (1) a gain of $181.9, net of tax effect, from the adoption
of DIG Issue No. C20; (2) a loss of $1.5 associated with the adoption of FIN
46-R and the deconsolidation of the three Trusts which issued the HIGH TIDES.
The loss of $1.5 represents the reversal of a gain, net of tax effect,
recognized prior to the adoption of FIN 46-R on our repurchase of $37.5 of the
value of HIGH TIDES by issuing shares of our common stock valued at $35.0; and
(3) a gain of $0.5, net of tax effect, from the adoption of SFAS No. 143.
Net Income
2003 2002 $ Change % Change
----------- ----------- ------------ ------------
Net income................................................................ $ 282.0 $ 118.6 $ 163.4 137.8%
Our growing portfolio of operating power generation facilities contributed
to a 13% increase in electric generation production for the year ended December
31, 2003, compared to the same period in 2002. Electric generation and marketing
revenue increased 15.3% for the year ended December 31, 2003, as electricity and
steam revenue increased by $1,442.9 or 44.9%, as a result of the higher
production and higher electricity prices. This was partially offset by a decline
in sales of purchased power for hedging and optimization. Operating results for
the year ended December 31, 2003, reflect a decrease in average spark spreads
per MWh compared with the same period in 2002. While we experienced an increase
in realized electricity prices in 2003, this was more than offset by higher fuel
expense. In 2003 we recorded other revenue of $67.3 in connection with our
settlement with Enron, primarily related to the termination of commodity
contracts following the Enron bankruptcy.
Plant operating expense, interest expense and depreciation were higher due
to the additional plants in operation. In 2003 generation did not increase
commensurately with new average capacity coming on line (lower baseload capacity
factor). Because of that and due to lower spark spreads per MWh, our spark
spread margins did not keep pace with the additional operating and depreciation
costs associated with the new capacity, and gross profit for the year ended
December 31, 2003, decreased approximately 36%, compared to the same period in
2002. During 2003 overall financial results significantly benefited from $278.6
of net pre-tax gains recorded in connection with the repurchase of various
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issuances of debt and preferred securities at a discount, and a gain of $52.8
from the termination of the AMS power contract at the Acadia Energy Center, a
gain of $57.0 from the termination of a power contract at the RockGen Energy
Center, a gain of $62.2 from the sale of oil and gas assets to the CNGT and an
after-tax gain of $180.9 due to the cumulative effect of changes in accounting
principle.
Liquidity and Capital Resources
Our business is capital intensive. Our ability to capitalize on growth
opportunities and to service the debt we incurred in order to construct and
operate our current fleet of power plants is dependent on the continued
availability of capital on attractive terms. The availability of such capital in
today's environment is uncertain. To date, we have obtained cash from our
operations; borrowings under credit facilities; issuances of debt, equity, trust
preferred securities and convertible debentures and contingent convertible
notes; proceeds from sale/leaseback transactions; sale or partial sale of
certain assets; contract monetizations and project financings. We have utilized
this cash to fund our operations, service or prepay debt obligations, fund
acquisitions, develop and construct power generation facilities, finance capital
expenditures, support our hedging, balancing, optimization and trading
activities, and meet our other cash and liquidity needs. We also reinvest our
cash from operations into our business development and construction program or
use it to reduce debt, rather than to pay cash dividends. As discussed below, we
have a liquidity-enhancing program underway for funding the completion of, and
in some cases extending the completion of, the projects remaining in our current
construction portfolio, for refinancing and for general corporate purposes.
In March 2004, we refinanced our $2.5 billion secured revolving
construction financing facility through our CalGen subsidiary (formerly CCFC II)
which was scheduled to mature in November 2004. CalGen completed a secured
institutional term loans, notes and revolving credit facility financing, which
replaced the old CCFC II facility. We realized total proceeds from the financing
in the amount of $2.6 billion, before transaction costs and fees. As of December
31, 2004, there was an aggregate principal amount outstanding of $2.6 billion on
the secured institutional term loans, notes and revolving credit facility.
In 2003 and 2004, we repurchased $1.2 billion of the outstanding principal
amount of 2006 Convertible Senior Notes, with proceeds of financings we
consummated in July 2003, through equity swaps and with the proceeds of our
offering of 4.75% Contingent Convertible Senior Notes due 2023 ("2023
Convertible Senior Notes") in November 2003 and January 2004. The repurchases
were made in open market and privately negotiated transactions and, in February
2004, we initiated a cash tender offer for all of the outstanding 2006
Convertible Senior Notes for a price of par plus accrued interest. Approximately
$409.4 million aggregate principal amount of the 2006 Convertible Senior Notes
were tendered pursuant to the tender offer, for which we paid a total of $412.8
million (including accrued interest of $3.4 million). On December 27, 2004, we
repurchased $70.8 million of the remaining outstanding 2006 Convertible Senior
Notes for par plus accrued interest in connection with the holders' exercise of
their right to require us to repurchase their notes. At December 31, 2004, only
$1.3 million in aggregate principal amount of 2006 Convertible Senior Notes
remains outstanding.
In October 2004, all of our outstanding HIGH TIDES I and HIGH TIDES II were
redeemed. At December 31, 2004, $517.5 million of principal amount of HIGH TIDES
III remained outstanding, including $115.0 million held by Calpine. The HIGH
TIDES III are scheduled to be remarketed no later than August 1, 2005. In the
event of a failed remarketing, the relevant HIGH TIDES III will remain
outstanding as convertible securities at a term rate equal to the treasury rate
plus 6% per annum and with a term conversion price equal to 105% of the average
closing price of our common stock for the five consecutive trading days after
the applicable final failed remarketing termination date. While a failed
remarketing of our HIGH TIDES III would not have a material effect on our
liquidity position, it would impact our calculation of diluted earnings per
share ("EPS") and increase our interest expense. Even with a successful
remarketing, we would expect to have an increased dilutive impact on our EPS
based on a revised conversion ratio. See Note 12 of the Notes to Consolidated
Financial Statements for a summary of HIGH TIDES repurchased or redeemed by the
Company through December 31, 2004.
See Note 12 of the Notes to Consolidated Financial Statements for more
information related to other financings and repurchases of various issuances of
debt in 2004.
We expect to have sufficient liquidity from cash flow from operations,
borrowings available under lines of credit, access to sale/leaseback and project
financing markets, sale or monetization of certain assets and cash balances to
satisfy all obligations under our outstanding indebtedness, and to fund
anticipated capital expenditures and working capital requirements for the next
twelve months, but, as described above, we face several challenges over the next
two to three years as our cash requirements (including our refinancing
obligations) are expected to exceed our unrestricted cash on hand and cash from
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operations. Accordingly, we have in place a liquidity-enhancing program which
includes possible sales or monetizations of certain of our assets, and whether
we will have sufficient liquidity will depend, to a certain extent, on the
success of that program. On December 31, 2004, our liquidity totaled
approximately $1.5 billion. This includes cash and cash equivalents on hand of
$0.7 billion, current portion of restricted cash of approximately $0.6 billion
and approximately $0.2 billion of borrowing capacity under our various credit
facilities.
Factors that could affect our liquidity and capital resources are also
discussed below in "Capital Spending" and above in Item 1. "Business -- Risk
Factors."
Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:
Years Ended December 31,
2004 2003 2002
------------ ------------ ------------
(In thousands)
Beginning cash and cash equivalents............................................... $ 962,108 $ 575,714 $ 1,578,124
------------ ------------ ------------
Net cash provided by:
Operating activities............................................................ $ 9,895 $ 290,559 $ 1,068,466
Investing activities............................................................ (401,426) (2,515,365) (3,837,827)
Financing activities............................................................ 167,052 2,623,986 1,757,396
Effect of exchange rates changes on cash and cash equivalents, including
discontinued operations cash................................................... 16,101 13,140 (2,693)
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents............................ $ (208,378) $ 412,320 $ (1,014,658)
Change in discontinued operations cash classified as current assets
held for sale.................................................................. (35,707) (25,926) 12,248
Net increase (decrease) in cash and cash equivalents............................ (244,085) 386,394 (1,002,410)
------------ ------------ ------------
Ending cash and cash equivalents.................................................. $ 718,023 $ 962,108 $ 575,714
============ ============ ============
Operating activities for the year ended December 31, 2004, provided net
cash of $9.9 million, compared to $290.6 million for the same period in 2003.
Operating cash flows in 2004 benefited from the receipt of $100.6 million from
the termination of power purchase agreements for two of our New Jersey power
plants and $16.4 million from the restructuring of a long-term gas supply
contract. During the year ended December 31, 2004, operating assets and
liabilities used approximately $137.6 million, as compared to having used $609.8
million in the same period in 2003. Uses of funds included accounts receivable,
which increased by $99.4 million as our total revenues in 2004 (after the
netting of approximately $1.7 billion of purchase power expense with sales of
purchased power pursuant to EITF Issue No. 03-11) increased by approximately
$358.9 million. Also, cash operating lease payments exceeded recognized expense
by $83.7 million and accrued liabilities were reduced, through payments, for
sales and property taxes and net margin deposits posted to support CES trading
activity increased by $60.9 million. These uses of funds were partially offset
by an increase of $231.8 million in accounts payable and accrued expense
(including an increase in interest expense payable of $64.5 million). The
increase in such deposits, which serve as collateral for certain of our
commodity transactions that have a net exposure to a counterparty on a
mark-to-market basis, is reflective of movements in commodity prices and a
higher mix of margin deposits posted relative to letters of credit.
Investing activities for the year ended December 31, 2004, consumed net
cash of $401.4 million, as compared to $2,515.4 million in the same period of
2003. Capital expenditures for the completion of our power facilities decreased
in 2004, as there were fewer projects under construction. Investing activities
in 2004 reflect the receipt of $148.6 million from the sale of our 50% interest
in the Lost Pines I Power Plant, $626.6 million from the sale of our Canadian
oil and gas reserves, $218.7 million from the sale of our Rocky Mountain oil and
gas reserves, plus $85.4 million of proceeds from the sale of a subsidiary
holding power purchase agreements for two of our New Jersey power plants. We
also reported a $181.0 million increase in cash used for acquisitions in 2004
compared to 2003, as we used the proceeds from the Lost Pines sale and cash to
purchase the Los Brazos Power Plant, and we used cash on hand to purchase the
remaining 50% interest in the Aries Power Plant and the remaining 20% interest
in Calpine Cogeneration Corporation. Also, we used $110.6 million to purchase a
portion of HIGH TIDES III outstanding and provided $210.8 million by decreasing
restricted cash during 2004.
Financing activities for the year ended December 31, 2004, provided net
cash of $167.1 million, compared to $2,624.0 million in the prior year. We
continued our refinancing program in 2004 by raising $2.6 billion to refinance
$2.5 billion of CalGen project financing before payment for fees and expenses of
-22-
the refinancing. In 2004 we also raised $250 million from the issuance of the
2023 Convertible Senior Notes pursuant to an option exercise by one of the
initial purchasers and $617.5 from the issuance of the 2014 Convertible Notes.
We raised $878.8 million from the issuance of Senior Notes, $360.0 million from
a preferred security offering and $1,179.4 million from various project
financings. Also, we repaid $635.4 million in project financing debt, and we
used $657.7 million to repurchase the outstanding 2006 Convertible Senior Notes
that could be put to us in December 2004. We used $177.0 million to repurchase a
portion of the 2023 Convertible Senior Notes, $871.3 million to repay and
repurchase various Senior Notes and $483.5 million to redeem the remainder of
HIGH TIDES I and II. In 2003, cash inflows primarily included $3.9 billion from
the issuance of senior secured notes and institutional term loans, $802.2
million from the PCF financing transaction, $785.5 million from the refinancing
of our CCFC I credit facility, $301.7 million from the issuance of secured notes
by our wholly owned subsidiary Gilroy Energy Center, LLC ("GEC"), $159.7 million
from secondary trust unit offerings from our CPIF, $82.8 million from the
monetization of one of our PSAs, $244.0 million from the sales of preferred
interests in the cash flows from certain of our facilities and additional
borrowings under our revolvers. This was partially offset by financing costs and
$5.0 billion in debt repayments and repurchases.
Liquidity and Finance Program Update -- Enhancing liquidity, reducing
corporate debt and addressing near-term debt maturities continued to drive our
financing program in 2004. During the year, we successfully enhanced our
financial position through a significant number of transactions:
o Refinanced CCFC II project debt through the issuance of $2.6 billion
of Calpine Generating Company secured institutional term loans, notes
and revolving credit facility;
o Completed approximately $2.1 billion of liquidity transactions
including the sale of our Canadian and certain U.S. natural gas
reserves for $870.1 million;
o Redeemed in full $598.5 million of HIGH TIDES I and II, and purchased
a portion of HIGH TIDES III, totaling $115.0 million; and
o Repurchased approximately $1.8 billion of existing corporate debt,
resulting in a net gain of $246.9 million after the write-off of
unamortized discounts and deferred financing costs.
Also, in early 2005, we:
o Obtained a $100 million, non-recourse credit facility to complete
construction of the Metcalf Energy Center in San Jose, California.
This was the first single-asset, merchant project financing in
California since the 2000-2001 energy crisis;
o Received funding on Calpine European Funding (Jersey) Limited's $260
million offering of Redeemable Preferred Shares due on July 30, 2005.
The net proceeds from this offering will ultimately be used as
permitted by our existing bond indentures;
o Completed a $400 million, 25-year, non-recourse sale/leaseback
transaction for the 560-MW Fox Energy Center under construction in
Kaukauna, Wisconsin; and
o Completed a $195 million, non-recourse project financing for
construction of the 525-MW Valladolid III Energy Center in Valladolid,
Mexico.
Counterparties and Customers -- Our customer and supplier base is
concentrated within the energy industry. Additionally, we have exposure to
trends within the energy industry, including declines in the creditworthiness of
our marketing counterparties. Currently, multiple companies within the energy
industry are in bankruptcy or have below investment grade credit ratings.
However, we do not currently have any significant exposures to counterparties
that are not paying on a current basis.
Letter of Credit Facilities -- At December 31, 2004 and 2003, we had
approximately $596.1 million and $410.8 million, respectively, in letters of
credit outstanding under various credit facilities to support our risk
management and other operational and construction activities. Of the total
letters of credit outstanding, $233.3 million and $272.1 million, respectively,
were in aggregate issued under the cash collateralized letter of credit facility
and the corporate revolving credit facility at December 31, 2004 and 2003,
respectively.
Commodity Margin Deposits and Other Credit Support -- As of December 31,
2004 and 2003, to support commodity transactions we had deposited net amounts of
$248.9 million and $188.0 million, respectively, in cash as margin deposits with
third parties, and we made gas and power prepayments of $78.0 million, and $60.6
million, respectively, and had letters of credit outstanding of $115.9 million
-23-
and $14.5 million, respectively. We use margin deposits, prepayments and letters
of credit as credit support for commodity procurement and risk management
activities. Future cash collateral requirements may increase based on the extent
of our involvement in standard contracts and movements in commodity prices and
also based on our credit ratings and general perception of creditworthiness in
this market. While we believe that we have adequate liquidity to support our
operations at this time, it is difficult to predict future developments and the
amount of credit support that we may need to provide as part of our business
operations.
Revised Capital Expenditure Program -- Following a comprehensive review of
our power plant development program, we announced in January 2002 the adoption
of a revised capital expenditure program which contemplated the completion of 27
power projects (representing 15,200 MW) then under construction. As of December
31, 2004, 24 of these facilities have subsequently achieved full or partial
commercial operation. Construction of advanced stage development projects is
expected to proceed only when there is an established market need through power
purchase agreements for additional generating resources at prices that will
allow us to meet our investment criteria, and when capital is available to us on
attractive terms. Our entire development and construction program is flexible
and subject to continuing review and revision based upon such criteria. Since
the adoption of the revised capital expenditure program, we have added several
projects now in development and construction and, currently, work on three
construction projects, Hillabee, Washington Parish and Fremont, has been largely
postponed until market conditions improve in the Southeast and Midwest market
areas. See "Capital Spending -- Development and Construction" below for more
information on our capital expenditure program.
Asset Sales -- As a result of the significant contraction in the
availability of capital for participants in the energy sector, we have adopted a
strategy of conserving our core strategic assets and disposing of certain less
strategically important assets, which serves primarily to strengthen our balance
sheet through repayment of debt. Set forth below are the completed asset
disposals:
On January 15, 2004, we completed the sale of our 50-percent undivided
interest in the 545-megawatt Lost Pines 1 Power Project to GenTex Power
Corporation, an affiliate of the Lower Colorado River Authority. Under the terms
of the agreement, we received a cash payment of $148.6 million and recorded a
pre-tax gain of $35.3 million. We subsequently closed on the purchase of the
Brazos Valley Power Plant for approximately $181.1 million in a tax deferred
like-kind exchange under IRS Section 1031, largely with the proceeds of the Lost
Pines I Power Project sale.
On February 18, 2004, one of our wholly owned subsidiaries closed on the
sale of natural gas properties to CNGT. We received net consideration of
Cdn$38.8 million ($29.2 million) and recorded a pre-tax gain of approximately
$6.8 million.
On September 1, 2004, in combination with CNGLP, a Delaware limited
partnership, we completed the sale of our Rocky Mountain gas reserves that were
primarily concentrated in two geographic areas: the Colorado Piceance Basin and
the New Mexico San Juan Basin. Together, these assets represent approximately
120 Bcfe of proved gas reserves, producing approximately 16.3 Mmcfe per day of
gas. Under the terms of the agreement we received net cash payments of
approximately $218.7 million, and recorded a pre-tax gain of approximately
$103.7 million.
On September 2, 2004, we completed the sale of our Canadian natural gas
reserves and petroleum assets. These Canadian assets represented approximately
221 Bcfe of proved reserves, producing approximately 61 Mmcfe per day. Included
in this sale was our 25% interest in approximately 80 Bcfe of proved reserves
(net of royalties) and 32 Mmcfe per day of production owned by CNGT. Under the
terms of the agreement, we received cash payments of approximately Cdn$802.9
million, or approximately $622.2 million. We recorded a pre-tax gain of
approximately $100.6 million on the sale of our Canadian assets.
We believe that our completion of the financing and liquidity transactions
described above in the current difficult conditions affecting capital
availability in the market, and our sector in particular, demonstrate our
probable ability to raise capital on acceptable terms in the future, although
availability of capital has tightened significantly throughout the power
generation industry and, therefore, there can be no assurance that we will have
access to capital in the future as and when we may desire.
See Note 10 of the Notes to Consolidated Financial Statements for a
discussion of subsequent sales of the Saltend Energy Centre and our remaining
oil and gas assets in July 2005.
Credit Considerations -- On September 23, 2004, S&P assigned our first
priority senior secured debt a rating of B+ and reaffirmed their ratings on our
second priority senior secured debt at B, our corporate rating at B (with
outlook negative), our senior unsecured debt rating at CCC+, and our preferred
stock rating at CCC.
-24-
On October 4, 2004, Fitch, Inc. assigned our first priority senior secured
debt a rating of BB-. At that time, Fitch also downgraded our second priority
senior secured debt from BB- to B+, downgraded our senior unsecured debt rating
from B- to CCC+, and reconfirmed our preferred stock rating at CCC. Fitch's
rating outlook for the Company is stable.
Moody's Investors Service currently has a senior implied rating on the
Company of B2 (with a stable outlook), and they rate our senior unsecured debt
at Caa1, and our preferred stock at Caa3.
Many other issuers in the power generation sector have also been downgraded
by one or more of the ratings agencies during this period. Such downgrades can
have a negative impact on our liquidity by reducing attractive financing
opportunities and increasing the amount of collateral required by trading
counterparties.
Performance Indicators -- We believe the following factors are important in
assessing our ability to continue to fund our growth in the capital markets: (a)
our debt-to-capital ratio; (b) various interest coverage ratios; (c) our credit
and debt ratings by the rating agencies; (d) the trading prices of our senior
notes in the capital markets; (e) the price of our common stock on The New York
Stock Exchange; (f) our anticipated capital requirements over the coming
quarters and years; (g) the profitability of our operations; (h) the non- GAAP
financial measures and other performance metrics discussed in "Performance
Metrics" below; (i) our cash balances and remaining capacity under existing
revolving credit construction and general purpose credit facilities; (j)
compliance with covenants in existing debt facilities; (k) progress in raising
new or replacement capital; and (l) the stability of future contractual cash
flows.
Off-Balance Sheet Commitments -- In accordance with SFAS No. 13 and SFAS
No. 98, "Accounting for Leases" our operating leases, which include certain
sale/leaseback transactions, are not reflected on our balance sheet. All
counterparties in these transactions are third parties that are unrelated to us
except as disclosed for Acadia in Note 7 of the Notes to Consolidated Financial
Statements. The sale/leaseback transactions utilize special-purpose entities
formed by the equity investors with the sole purpose of owning a power
generation facility. Some of our operating leases contain customary restrictions
on dividends, additional debt and further encumbrances similar to those
typically found in project finance debt instruments. We guarantee $1.6 billion
of the total future minimum lease payments of our consolidated subsidiaries
related to our operating leases. We have no ownership or other interest in any
of these special-purpose entities. See Note 22 of the Notes to Consolidated
Financial Statements for the future minimum lease payments under our power plant
operating leases.
In accordance with Accounting Principles Board ("APB") Opinion No. 18, "The
Equity Method of Accounting For Investments in Common Stock" and FIN 35,
"Criteria for Applying the Equity Method of Accounting for Investments in Common
Stock (An Interpretation of APB Opinion No. 18)," the debt on the books of our
unconsolidated investments in power projects is not reflected on our balance
sheet (see Note 7 of the Notes to Consolidated Financial Statements). At
December 31, 2004, investee debt was approximately $133.9 million. Of the $133.9
million, $63.4 million related to our investment in AELLC, for which we used the
cost method of accounting as of December 31, 2004. Based on our pro rata
ownership share of each of the investments, our share would be approximately
$46.6 million, which includes our share for AELLC of $20.5 million. Please see
Note 7 of the Notes to Consolidated Financial Statements for more information on
the cost method of accounting used for AELLC. However, all such debt is
non-recourse to us. For the Aries Power Plant construction debt, Aquila Inc. and
Calpine provided support arrangements until construction was completed to cover
any cost overruns. See Note 7 of the Notes to Consolidated Financial Statements
for additional information on our equity method and cost method unconsolidated
investments in power projects and oil and gas properties.
Commercial Commitments -- Our primary commercial obligations as of December
31, 2004, are as follows (in thousands):
Amounts of Commitment Expiration per Period
----------------------------------------------------------------------------------
Total
Amounts
Commercial Commitments 2005 2006 2007 2008 2009 Thereafter Committed
- ------------------------------------------------ ---------- ---------- ---------- ---------- ---------- ---------- ----------
Guarantee of subsidiary debt.................... $ 18,333 $ 16,284 $ 18,798 $1,930,657 $ 19,848 $1,133,896 $3,137,816
Standby letters of credit....................... 589,230 3,641 2,802 400 -- -- 596,073
Surety bonds.................................... -- -- -- -- -- 12,531 12,531
Guarantee of subsidiary operating
lease payments................................ 83,169 81,772 82,487 115,604 113,977 1,163,783 1,640,792
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total.......................................... $ 690,732 $ 101,697 $ 104,087 $2,046,661 $ 133,825 $2,310,210 $5,387,212
========== ========== ========== ========== ========== ========== ==========
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Our commercial commitments primarily include guarantees of subsidiary debt,
standby letters of credit and surety bonds to third parties and guarantees of
subsidiary operating lease payments. The debt guarantees consist of parent
guarantees for the finance subsidiaries and project financing for the Broad
River Energy Center and the Pasadena Power Plant. The debt guarantees and
operating lease payments are also included in the contractual obligations table
above. We also issue guarantees for normal course of business activities.
We have guaranteed the principal payment of $2,139.7 million and $2,448.6
million, respectively, of senior notes as of December 31, 2004 and 2003, for two
wholly owned finance subsidiaries of Calpine, Calpine Canada Energy Finance ULC
and Calpine Canada Energy Finance II ULC. As of December 31, 2004, we have
guaranteed $275.1 million and $72.4 million, respectively, of project financing
for the Broad River Energy Center and Pasadena Power Plant and $291.6 million
and $71.8 million, respectively, as of December 31, 2003, for these power
plants. In 2004 and 2003 we have debenture obligations in the amount of $517.5
million and $1,153.5 million, respectively, the payment of which will fund the
obligations of the Trusts (see Note 12 for more information). We agreed to
indemnify Duke Capital Corporation $101.4 million and $101.7 million as of
December 31, 2004 and 2003, respectively, in the event Duke Capital Corporation
is required to make any payments under its guarantee of the lease of the Hidalgo
Energy Center. As of December 31, 2004 and 2003, we have also guaranteed $31.7
million and $35.6 million, respectively, of other miscellaneous debt. All of the
guaranteed debt is recorded on our Consolidated Balance Sheet.
Contractual Obligations -- Our contractual obligations related to
continuing operations as of December 31, 2004, are as follows (in thousands):
2005 2006 2007 2008 2009 Thereafter Total
----------- ----------- ----------- ----------- ----------- ----------- -----------
Other Contractual Obligations .......... $ 49,520 $ 7,995 $ 2,089 $ 2,096 $ 2,500 $ 75,437 $ 139,637
=========== =========== =========== =========== =========== =========== ===========
Total operating lease obligations(1) ... $ 266,399 $ 252,511 $ 252,849 $ 250,238 $ 244,601 $ 2,321,601 $ 3,588,199
=========== =========== =========== =========== =========== =========== ===========
Debt:
Unsecured Senior Notes(2) .............. $ 705,949 $ 264,258 $ 360,878 $ 1,968,660 $ 221,539 $ 1,273,333 $ 4,794,617
Second Priority Senior Secured Notes(2). 12,500 12,500 1,209,375 -- -- 2,443,150 3,677,525
First Priority Senior Secured Notes(2).. -- -- -- -- -- 778,971 778,971
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total Senior Notes .................... $ 718,449 $ 276,758 $ 1,570,253 $ 1,968,660 $ 221,539 $ 4,495,454 $ 9,251,113
CCFC 1(4) .............................. 3,208 3,208 3,208 3,208 365,349 408,569 786,750
CALGEN(4) .............................. -- -- 4,174 12,050 829,875 1,549,233 2,395,332
Convertible Senior Notes Due 2006, 2014
and 2023(2) .......................... -- 1,326 -- -- -- 1,253,972 1,255,298
Notes payable and borrowings under
lines of credit(4)(5) ................ 197,016 188,756 143,962 104,555 106,221 108,277 848,787
Notes payable to Calpine Capital
Trusts(2) ............................ -- -- -- -- -- 517,500 517,500
Preferred interests(4) ................. 8,641 369,480 8,990 12,236 16,228 90,962 506,537
Capital lease obligation(4) ............ 5,490 6,538 7,428 9,765 10,925 248,773 288,919
Construction/project financing(4)(6) ... 93,393 89,355 103,423 100,340 105,299 1,507,241 1,999,051
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total debt(5)(9)(3) .................. $ 1,026,197 $ 935,421 $ 1,841,438 $ 2,210,814 $ 1,655,436 $10,179,981 $17,849,287
=========== =========== =========== =========== =========== =========== ===========
Interest payments on debt obligations
(10) ................................. $ 1,473,629 $ 1,462,291 $ 1,356,035 $ 1,130,214 $ 1,003,534 $ 3,422,874 $ 9,848,577
=========== =========== =========== =========== =========== =========== ===========
Interest rate swap agreement payments .. $ 20,964 $ 13,945 $ 11,770 $ 10,051 $ 9,036 $ 14,102 $ 79,868
=========== =========== =========== =========== =========== =========== ===========
Purchase obligations:
Turbine commitments .................... 27,463 4,862 977 -- -- -- 33,302
Commodity purchase obligations(7) ...... 1,365,183 726,109 619,553 460,277 334,676 1,001,114 4,506,911
Land leases ............................ 4,234 4,428 4,609 5,146 5,640 364,136 388,193
Long-term service agreements ........... 58,905 84,635 120,385 74,448 70,544 710,137 1,119,054
Costs to complete construction projects. 699,174 449,312 189,806 -- -- -- 1,338,292
Other purchase obligations ............. 55,201 26,853 25,481 25,172 24,985 470,524 628,217
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total purchase obligations(8) ........ $ 2,210,160 $ 1,296,199 $ 960,811 $ 565,043 $ 435,845 $ 2,545,911 $ 8,013,969
=========== =========== =========== =========== =========== =========== ===========
- ------------
<FN>
(1) Included in the total are future minimum payments for power plant operating
leases, office and equipment leases and two tolling agreements with Acadia
Energy Center accounted for as leases (See Note 7 of the Notes to
Consolidated Financial Statements for more information).
(2) An obligation of or with recourse to Calpine Corporation.
(3) The table above does not reflect the repurchases of $80.6 million
convertible Senior Notes and Senior Notes subsequent to December 31, 2004.
-26-
(4) Structured as an obligation(s) of certain subsidiaries of Calpine
Corporation without recourse to Calpine Corporation. However, default on
these instruments could potentially trigger cross-default provisions in
certain other debt instruments.
(5) A note payable totaling $125.5 million associated with the sale of the PG&E
note receivable to a third party is excluded from notes payable and
borrowings under lines of credit for this purpose as it is a noncash
liability. If the $125.5 million is summed with the $848.8 (total notes
payable and borrowings under lines of credit) million from the table above,
the total notes payable and borrowings under lines of credit would be
$974.3 million, which agrees to the Consolidated Balance Sheet sum of the
current and long-term notes payable and borrowings under lines of credit
balances on the Consolidated Balance Sheet. See Note 8 of the Notes to
Consolidated Financial Statements for more information concerning this
note. Total debt of $17,849.3 million from the table above summed with the
$125.5 million totals $17,974.8 million, which agrees to the total debt
amount in Note 11 of the Notes to Consolidated Financial Statements.
(6) Included in the total are guaranteed amounts of $275.1 million and $282.9
million, respectively, of project financing for the Broad River Energy
Center and Pasadena Power Plant.
(7) The amounts presented here include contracts for the purchase,
transportation, or storage of commodities accounted for as executory
contracts or normal purchase and sales and, therefore, not recognized as
liabilities on our Consolidated Balance Sheet. See "Financial Market Risks"
for a discussion of our commodity derivative contracts recorded at fair
value on our Consolidated Balance Sheet.
(8) The amounts included above for purchase obligations include the minimum
requirements under contract. Also included in purchase obligations are
employee agreements. Agreements that we can cancel without significant
cancellation fees are excluded.
(9) See Item 1. "Business -- Risk Factors" for a discussion of the estimated
amount of debt that must be repurchased pursuant to our indentures.
(10) Interest payments on debt obligations have not been decreased for the
requirement to repurchase or redeem approximately $520 million of
indebtedness, per current estimates, pursuant to our indentures, as the
specific debt instruments are not known. However, the $520 million of
indebtedness is reflected in this table as due in 2005.
</FN>
Debt securities repurchased by Calpine during 2004 and 2003 totaled
$1,668.3 million and $1,853.4 million, respectively, in aggregate outstanding
principal amount for a repurchase price of $1,394.0 million and $1,575.3
million, respectively, plus accrued interest. In 2004 we recorded a pre-tax gain
on these transactions in the amount of $274.4 million which was $254.8 million,
net of write-offs of $19.1 million of unamortized deferred financing costs and
$0.5 million of unamortized premiums or discounts. In 2003 we recorded a pre-
tax gain on these transactions in the amount of $278.1 million, which was $256.9
million, net of write-offs of $18.9 million of unamortized deferred financing
costs and $2.3 million of unamortized premiums or discounts. HIGH TIDES III
repurchased by Calpine during 2004 totaled $115.0 million in aggregate
outstanding principle amount at a repurchase price of $111.6 million plus
accrued interest. These exchanged HIGH TIDES III are reflected on the balance
sheets as an asset, versus being netted against the balance outstanding, due to
the deconsolidation of the Calpine Capital Trusts, which issued the HIGH TIDES
III, upon the adoption of FIN 46-R. The following table summarizes the total
debt securities repurchased (in millions):
2004 2003
--------------------- ---------------------
Principal Amount Principal Amount
Debt Security and HIGH TIDES Amount Paid Amount Paid
- -------------------------------- --------- --------- --------- ---------
2006 Convertible Senior Notes... $ 658.7 $ 657.7 $ 474.9 $ 458.8
2023 Convertible Senior Notes... 266.2 177.0 -- --
8 1/4% Senior Notes Due 2005.... 38.9 34.9 25.0 24.5
10 1/2% Senior Notes Due 2006... 13.9 12.4 5.2 5.1
7 5/8% Senior Notes Due 2006.... 103.1 96.5 35.3 32.5
8 3/4% Senior Notes Due 2007.... 30.8 24.4 48.9 45.0
7 7/8% Senior Notes Due 2008.... 78.4 56.5 74.8 58.3
8 1/2% Senior Notes Due 2008.... 344.3 249.4 48.3 42.3
8 3/8% Senior Notes Due 2008.... 6.1 4.0 59.2 46.6
7 3/4% Senior Notes Due 2009.... 11.0 8.1 97.2 75.9
8 5/8% Senior Notes Due 2010.... -- -- 210.4 170.7
8 1/2% Senior Notes Due 2011.... 116.9 73.1 648.4 521.3
8 7/8% Senior Notes Due 2011.... -- -- 125.8 94.3
HIGH TIDES III.................. 115.0 111.6 -- --
--------- --------- --------- ---------
$ 1,783.3 $ 1,505.6 $ 1,853.4 $ 1,575.3
========= ========= ========= =========
-27-
During 2004 we exchanged 24.3 million shares of Calpine common stock in
privately negotiated transactions for approximately $115.0 million par value of
HIGH TIDES I and HIGH TIDES II. During 2003, debt securities, exchanged for 23.5
million shares of Calpine common stock in privately negotiated transactions,
totaled $145.0 million in aggregate outstanding principal amount plus accrued
interest. We recorded a pre-tax gain on these transactions in the amount of
$20.2 million, net of write-offs of unamortized deferred financing costs and the
unamortized premiums or discounts. Additionally, during 2003, we exchanged 6.5
million shares of Calpine common stock in privately negotiated transactions for
approximately $37.5 million par value of HIGH TIDES I. These repurchased HIGH
TIDES I were reflected on the balance sheet as an asset, versus being netted
against the balance outstanding, due to the deconsolidation of the Trusts, which
issued the HIGH TIDES, upon the adoption of FIN 46-R.
On October 20, 2004, the Company repaid $636 million of convertible
subordinate debentures held by Calpine Capital Trusts which used those proceeds
to redeem its outstanding HIGH TIDES I and HIGH TIDES II. The redemption of the
HIGH TIDES I and HIGH TIDES II included securities previously purchased and held
by the Company and resulted in a realized gain of approximately $6.1 million.
The following table summarizes the total debt securities and HIGH TIDES
exchanged for common stock (in millions):
2004 2003
--------------------- ---------------------
Common Common
Principal Stock Principal Stock
Debt Securities and HIGH TIDES Amount Issued Amount Issued
- -------------------------------- --------- --------- --------- ---------
2006 Convertible Senior Notes... $ -- -- $ 65.0 12.0
8 1/2% Senior Notes Due 2008.... -- -- 55.0 8.1
8 1/2% Senior Notes Due 2011.... -- -- 25.0 3.4
HIGH TIDES I.................... 40.0 8.5 37.5 6.5
HIGH TIDES II................... 75.0 15.8 -- --
--------- --------- --------- ---------
$ 115.0 24.3 $ 182.5 30.0
========= ========= ========= =========
Debt Covenant and Indenture Compliance
Our senior notes indentures and our credit facilities contain financial and
other restrictive covenants that limit or prohibit our ability to incur
indebtedness, make prepayments on or purchase indebtedness in whole or in part,
pay dividends, make investments, lease properties, engage in transactions with
affiliates, create liens, consolidate or merge with another entity or allow one
of our subsidiaries to do so, sell assets, and acquire facilities or other
businesses. We are currently in compliance with all of such financial and other
restrictive covenants, except as discussed below. Any failure to comply could
give holders of debt under the relevant instrument the right to accelerate the
maturity of all debt outstanding thereunder if the default was not cured or
waived. In addition, holders of debt under other instruments typically would
have cross-acceleration provisions, which would permit them also to elect to
accelerate the maturity of their debt if another debt instrument was accelerated
upon the occurrence of such an uncured event of default.
Indenture Compliance -- Our various indentures place conditions on our
ability to issue indebtedness, including further limitations on the issuance of
additional debt if our interest coverage ratio (as defined in the various
indentures) is below 2:1. Currently, our interest coverage ratio (as so defined)
is below 2:1 and, consequently, our indentures generally would not allow us to
issue new debt, except for (i) certain types of new indebtedness that refinances
or replaces existing indebtedness, and (ii) non-recourse debt and preferred
equity interests issued by our subsidiaries for purposes of financing certain
types of capital expenditures, including plant development, construction and
acquisition expenses. In addition, if and so long as our interest coverage ratio
is below 2:1, our indentures will limit our ability to invest in unrestricted
subsidiaries and non-subsidiary affiliates and make certain other types of
restricted payments. Moreover, certain of our indentures will prohibit any
further investments in non-subsidiary affiliates if and for so long as our
interest coverage ratio (as defined therein) is below 1.75:1 and, as of December
31, 2004, such interest coverage ratio had fallen below 1.75:1.
In September 2004, we resolved a dispute with Credit Suisse First Boston
("CSFB"), by amending and restating a Letter of Credit and Reimbursement
Agreement pursuant to which CSFB issues a letter of credit with a maximum face
amount of $78.3 million for our account. CSFB had previously advised us that it
believed that we may have failed to comply with certain covenants under the
Letter of Credit and Reimbursement Agreement related to our ability to incur
indebtedness and grant liens.
Calpine has guaranteed the payment of a portion of the rents due under the
lease of the Greenleaf generating facilities in California, which lease is
between an owner trustee acting on behalf of Union Bank of California, as
-28-
lessor, and a Calpine subsidiary, Calpine Greenleaf, Inc., as lessee. Calpine
does not currently meet the requirements of a financial covenant contained in
the guarantee agreement. The lessor has waived this non-compliance through April
30, 2005, and Calpine is currently in discussions with the lessor concerning the
possibility of modifying the lease and/or Calpine's guarantee thereof so as to
eliminate or modify the covenant in question. In the event the lessor's waiver
were to expire prior to completion of this amendment, the lessor could at that
time elect to accelerate the payment of certain amounts owing under the lease,
totaling approximately $15.9 million. In the event the lessor were to elect to
require Calpine to make this payment, the lessor's remedy under the guarantee
and the lease would be limited to taking steps to collect damages from Calpine;
the lessor would not be entitled to terminate or exercise other remedies under
the Greenleaf lease.
In connection with several of our subsidiaries' lease financing
transactions (Greenleaf, Pasadena, Broad River, RockGen and South Point) the
insurance policies we have in place do not comply in every respect with the
insurance requirements set forth in the financing documents. We have requested
from the relevant financing parties, and are expecting to receive, waivers of
this noncompliance. While failure to have the required insurance in place is
listed in the financing documents as an event of default, the financing parties
may not unreasonably withhold their approval of our waiver request so long as
the required insurance coverage is not reasonably available or commercially
feasible and we deliver a report from our insurance consultant to that effect.
We have delivered the required insurance consultant reports to the relevant
financing parties and therefore anticipate that the necessary waivers will be
executed shortly.
We own a 32.3% interest in AELLC. AELLC owns the 136 MW Androscoggin Energy
Center located in Maine and is a joint venture between us, and affiliates of
Wisvest Corporation and IP. AELLC had construction debt of $60.3 million
outstanding as of December 31, 2004. The debt is non-recourse to Calpine
Corporation (the "AELLC Non-Recourse Financing"). On November 3, 2004, a jury
verdict was rendered against AELLC in a breach of contract dispute with IP. See
Note 25 of the Notes to Consolidated Financial Statements for more information
about this legal proceeding. We recorded our $11.6 million share of the award
amount in the third quarter of 2004. On November 26, 2004, AELLC filed a
voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. As a
result of the bankruptcy, we lost significant influence and control of the
project and have adopted the cost method of accounting for our investment in
Androscoggin. Also, in December 2004, we determined that our investment in
Androscoggin was impaired and recorded a $5.0 million impairment charge.
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the indentures and credit agreement governing
the various tranches of our second-priority secured indebtedness (collectively,
the "Second Priority Secured Debt Instruments"). We have designated certain of
our subsidiaries as "unrestricted subsidiaries" under the Second Priority
Secured Debt Instruments. A subsidiary with "unrestricted" status thereunder
generally is not required to comply with the covenants contained therein that
are applicable to "restricted subsidiaries." The Company has designated Calpine
Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as
"unrestricted subsidiaries" for purposes of the Second Priority Secured Debt
Instruments. The following table sets forth selected balance sheet information
of Calpine Corporation and restricted subsidiaries and of such unrestricted
subsidiaries at December 31, 2004, and selected income statement information for
the year ended December 31, 2004 (in thousands):
Calpine
Corporation
and Restricted Unrestricted
Subsidiaries Subsidiaries Eliminations Total
-------------- -------------- -------------- -------------
Assets........................................................... $ 27,001,518 $ 438,955 $ (224,385) $ 27,216,088
============= ============= ============= ============
Liabilities...................................................... $ 21,981,372 $ 253,598 $ -- $ 22,234,970
============= ============= ============= ============
Total revenue.................................................... $ 8,776,889 $ 19,213 $ (15,247) $ 8,780,855
Total cost of revenue............................................ (8,403,293) (23,927) 17,119 (8,410,101)
Interest income.................................................. 44,119 25,824 (15,172) 54,771
Interest expense................................................. (1,103,007) (13,793) -- (1,116,800)
Other............................................................ 452,202 (3,388) -- 448,814
------------- ------------- ------------- ------------
Net income (loss)................................................ $ (233,090) $ 3,929 $ (13,300) $ (242,461)
============= ============= ============= ============
Bankruptcy-Remote Subsidiaries -- Pursuant to applicable transaction
agreements, we have established certain of our entities separate from Calpine
and our other subsidiaries. At December 31, 2004, these entities included: Rocky
Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside
-29-
Holdings, LLC, Calpine Energy Management, L.P., CES GP, LLC, Power Contract
Financing, LLC, Power Contract Financing III, LLC, Calpine Northbrook Energy
Marketing, LLC, Calpine Northbrook Energy Marketing Holdings, LLC, Gilroy Energy
Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King
City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine
King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of
Calpine Securities Company, L.P.), Calpine Fox Holdings, LLC and Calpine Fox
LLC. The following disclosures are required under certain applicable agreements
and pertain to some of these entities.
On May 15, 2003, our wholly owned indirect subsidiary, Calpine Northbrook
Energy Marketing, LLC ("CNEM"), completed an offering of $82.8 million secured
by an existing power sales agreement with the Bonneville Power Administration
("BPA"). CNEM borrowed $82.8 million secured by the BPA contract, a spot market
power purchase agreement, a fixed price swap agreement and the equity interest
in CNEM. The $82.8 million loan is recourse only to CNEM's assets and the equity
interest in CNEM and is not guaranteed by us. CNEM was determined to be a
Variable Interest Entity ("VIE") in which we were the primary beneficiary.
Accordingly, the entity's assets and liabilities are consolidated into our
accounts.
Pursuant to the applicable transaction agreements, each of CNEM and its
parent, CNEM Holdings, LLC, has been established as an entity with its existence
separate from Calpine and our other subsidiaries. In accordance with FIN 46-R,
we consolidate these entities. See Note 2 of the Notes to Consolidated Financial
Statements for more information on FIN 46-R. The power sales agreement with BPA
has been acquired by CNEM from CES and the spot market power purchase agreement
with a third party and the swap agreement have been entered into by CNEM and,
together with the $82.8 million loan, are assets and liabilities of CNEM,
separate from the assets and liabilities of Calpine and our other subsidiaries.
The only significant asset of CNEM Holdings, LLC is its equity interest in CNEM.
The proceeds of the $82.8 million loan were primarily used by CNEM to purchase
the power sales agreement with BPA.
The following table sets forth selected financial information of CNEM as of and
for the year ended December 31, 2004 (in thousands):
2004
----------
Assets................................................... $ 72,367
Liabilities.............................................. $ 56,222
Total revenue(1)......................................... $ 667
Total cost of revenue.................................... $ --
Interest expense......................................... $ 7,378
Net (loss)............................................... $ (6,884)
- ------------
(1) CNEM's contracts are derivatives and are recorded on a net mark-to-market
basis on our financial statements under SFAS No. 133, notwithstanding that
economically they are fully hedged.
See Note 12 of the Notes to Consolidated Financial Statements for further
information.
On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of CES,
completed an offering of two tranches of Senior Secured Notes due 2006 and 2010
(collectively called the "PCF Notes"), totaling $802.2 million. PCF's assets and
liabilities consist of cash, certain transferred power purchase and sales
agreements and the PCF Notes. PCF was determined to be a VIE in which we were
the primary beneficiary. Accordingly, the entity's assets and liabilities were
consolidated into our accounts.
Pursuant to the applicable transaction agreements, PCF has been established
as an entity with its existence separate from Calpine and our other
subsidiaries. In accordance with FIN 46-R, we consolidate this entity. See Note
2 of the Notes to Consolidated Financial Statements for more information on FIN
46-R. The above mentioned power purchase and sales agreements, which were
acquired by PCF from CES, and the PCF Notes are assets and liabilities of PCF,
separate from the assets and liabilities of Calpine and our other subsidiaries.
The proceeds of the PCF Notes were primarily used by PCF to purchase the power
purchase and sales agreements. The following table sets forth selected financial
information of PCF as of and for the year ended December 31, 2004 (in
thousands):
2004
-----------
Assets................................................... $ 801,368
Liabilities.............................................. $1,227,028
Total revenue............................................ $ 513,832
Total cost of revenue.................................... $ 469,632
Interest expense......................................... $ 66,116
Net (loss)............................................... $ (21,188)
See Note 12 of the Notes to Consolidated Financial Statements for further
information.
-30-
On September 30, 2003, GEC, a wholly owned subsidiary of our indirect
subsidiary GEC Holdings, LLC, completed an offering of $301.7 million of 4%
Senior Secured Notes Due 2011 (the "GEC Notes"). See Note 18 of the Notes to
Consolidated Financial Statements for more information on this secured
financing. In connection with the offering of the GEC Notes, we received funding
on a third party preferred equity investment in GEC Holdings, LLC totaling $74.0
million. This preferred interest meets the criteria of a mandatorily redeemable
financial instrument and has been classified as debt under the guidance of SFAS
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity," due to certain preferential distributions to the
third party. The preferential distributions are due semi-annually beginning in
March 2004 through September 2011 and total approximately $113.3 million over
the eight-year period. As of December 31, 2004 and 2003, there was $67.4 and
$74.0 million, respectively, outstanding under the preferred interest.
Pursuant to the applicable transaction agreements, GEC has been established
as an entity with its existence separate from Calpine and our other
subsidiaries. We consolidate these entities. One of our long-term power sales
agreements with CDWR has been acquired by GEC by means of a series of capital
contributions by CES and certain of its affiliates and is an asset of GEC, and
the GEC Notes and the preferred interest are liabilities of GEC, separate from
the assets and liabilities of Calpine and our other subsidiaries. In addition to
seven peaker power plants owned directly by GEC and the power sales agreement,
GEC's assets include cash and a 100% equity interest in each of Creed Energy
Center, LLC ("Creed") and Goose Haven Energy Center, LLC ("Goose Haven") each of
which is a wholly owned subsidiary of GEC. Each of Creed and Goose Haven has
been established as an entity with its existence separate from Calpine and our
other subsidiaries of the Company. GEC consolidates these entities. Creed and
Goose Haven each have assets consisting of various power plants and other
assets. The following table sets forth selected financial information of GEC as
of and for the year ended December 31, 2004 (in thousands):
2004
----------
Assets................................................... $ 624,132
Liabilities.............................................. $ 285,604
Total revenue............................................ $ 110,532
Total cost of revenue.................................... $ 54,214
Interest expense......................................... $ 20,567
Net income............................................... $ 36,864
See Note 12 of the Notes to Consolidated Financial Statements for further
information.
On April 29, 2003, we sold a preferred interest in a subsidiary that leases
and operates the 120 MW King City Power Plant to GE Structured Finance for $82.0
million. The preferred interest holder will receive approximately 60% of future
cash flow distributions based on current projections. We will continue to
provide O&M services. As of December 31, 2003, there was $82.0 million
outstanding under the preferred interest.
Pursuant to the applicable transaction agreements, each of Calpine King
City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine
King City Cogen, LLC), and Calpine King City, LLC (an indirect parent company of
Calpine Securities Company, L.P.), has been established as an entity with its
existence separate from Calpine and our other subsidiaries. We consolidate these
entities. The following table sets forth certain financial information relating
to these three entities as of December 31, 2004 (in thousands):
2004
-----------
Assets................................................... $ 481,482
Liabilities.............................................. $ 102,742
See Note 12 of the Notes to Consolidated Financial Statements for further
information.
On December 4, 2003, we announced that we had sold to a group of
institutional investors our right to receive payments from PG&E under the
Agreement between PG&E and Calpine Gilroy Cogen, L.P. ("Gilroy"), a California
Limited Partnership (PG&E Log No. 08C002) For Termination and Buy-Out of
Standard Offer 4 Power Purchase Agreement, executed by PG&E on July 1, 1999 (the
"Gilroy Receivable") for $133.4 million in cash. Because the transaction did not
satisfy the criteria for sales treatment under SFAS No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of Liabilities
- -- a Replacement of FASB Statement No. 125," it is reflected in the Consolidated
Financial Statements as a secured financing, with a note payable of $133.4
million. The receivable balance and note payable balance are both reduced as
PG&E makes payments to the buyer of the Gilroy Receivable. The $24.1 million
difference between the $157.5 million book value of the Gilroy Receivable at the
transaction date and the cash received will be recognized as additional interest
expense over the repayment term. We will continue to book interest income over
the repayment term and interest expense will be accreted on the amortizing note
payable balance.
-31-
Pursuant to the applicable transaction agreements, each of Gilroy and
Calpine Gilroy 1, Inc. (the general partner of Gilroy), has been established as
an entity with its existence separate from Calpine and our other subsidiaries.
We consolidate these entities. The following table sets forth the assets and
liabilities of Gilroy as of December 31, 2004 (in thousands):
2004
-----------
Assets................................................... $ 468,776
Liabilities.............................................. $ 127,505
See Note 8 of the Notes to Consolidated Financial Statements for further
information.
On June 2, 2004, our wholly-owned indirect subsidiary, Power Contract
Financing III, LLC ("PCF III"), issued $85.0 million of zero coupon notes
collateralized by PCF III's ownership of PCF. PCF III owns all of the equity
interests in PCF, which holds the CDWR contract monetized in June 2003 and
maintains a debt reserve fund, which had a balance of approximately $94.4
million at December 31, 2004. We received cash proceeds of approximately $49.8
million from the issuance of the zero coupon notes.
Pursuant to the applicable transaction agreements, PCF III has been
established as an entity with its existence separate from Calpine and our other
subsidiaries. We consolidate this entity. The following table sets forth the
assets and liabilities of PCF III as of December 31, 2004, which does not
include the balances of PCF III's subsidiary, PCF (in thousands):
2004
-----------
Assets................................................... $ 2,701
Liabilities.............................................. $ 52,388
On August 5, 2004, our wholly-owned indirect subsidiary, Calpine Energy
Management, L.P. ("CEM"), entered into a $250.0 million letter of credit
facility with Deutsche Bank whereby Deutsche Bank will support CEM's power and
gas obligations by issuing letters of credit. The facility expires in October
2005.
Pursuant to the applicable transaction agreements, CEM has been established
as an entity with its existence separate from Calpine and our other
subsidiaries. We consolidate this entity. The following table sets forth the
assets and liabilities of CEM as of December 31, 2004 (in thousands):
2004
-----------
Assets................................................... $ 35,851
Liabilities.............................................. $ 34,816
On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy
Center, LLC, wholly owned stand-alone subsidiaries of the Company's Calpine
Riverside Holdings, LLC subsidiary, received funding in the aggregate amount of
$661.5 million comprising $633.4 million of First Priority Secured Floating Rate
Term Loans Due 2011 and a $28.1 million letter of credit-linked deposit
facility.
Pursuant to the applicable transaction agreements, each of Rocky Mountain
Energy Center, LLC, Riverside Energy Center, LLC, and Calpine Riverside
Holdings, LLC has been established as an entity with its existence separate from
Calpine and our other subsidiaries. We consolidate these entities. The following
tables set forth the assets and liabilities of these entities as of December 31,
2004 (in thousands):
Rocky Mountain
Energy Center, LLC
2004
------------------
Assets................................................... $ 416,662
Liabilities.............................................. $ 277,157
Riverside
Energy Center, LLC
2004
------------------
Assets................................................... $ 667,794
Liabilities.............................................. $ 431,700
Calpine Riverside
Holdings, LLC
2004
------------------
Assets................................................... $ 241,893
Liabilities.............................................. $ --
-32-
On November 19, 2004, our wholly-owned indirect subsidiaries, Calpine Fox
LLC and its immediate parent company, Calpine Fox Holdings, LLC, entered into a
$400 million, 25-year, non-recourse sale/ leaseback transaction with affiliates
of GE Commercial Finance Energy Financial Services ("GECF") for the 560-megawatt
Fox Energy Center under construction in Wisconsin. Due to significant continuing
involvement, as defined in SFAS No. 98, "Accounting for Leases," the transaction
does not currently qualify for sale/ leaseback accounting under that statement
and has been accounted for as a financing. The proceeds received from GECF are
recorded as debt in our consolidated balance sheet. The power plant assets will
be depreciated over their estimated useful life and the lease payments will be
applied to principal and interest expense using the effective interest method
until such time as our continuing involvement is removed, expires or is
otherwise eliminated. Once we no longer have significant continuing involvement
in the power plant assets, the legal sale will be recognized for accounting
purposes and the underlying lease will be evaluated and classified in accordance
with SFAS No. 13, "Accounting for Leases."
Pursuant to the applicable transaction agreements, each of Calpine Fox, LLC
and Calpine Fox Holdings, LLC, has been established as an entity with its
existence separate from Calpine and our other subsidiaries. We consolidate these
entities. The following tables set forth the assets and liabilities of Calpine
Fox, LLC and Calpine Fox Holdings, LLC, respectively, as of December 31, 2004
(in thousands):
Calpine Fox, LLC
2004
----------------
Assets................................................... $ 377,705
Liabilities.............................................. $ 274,724
Calpine Fox
Holdings, LLC
2004
----------------
Assets................................................... $ 102,980
Liabilities.............................................. $ --
Capital Spending -- Development and Construction
Construction and development costs in process consisted of the following at
December 31, 2004 (dollars in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP(1) CIP Costs Equipment
-------- ----------- ----------- ----------- ----------
Projects in construction(2)........................................ 10 $ 3,194,530 $ 1,094,490 $ -- $ --
Projects in advanced development................................... 10 670,806 520,036 102,829 --
Projects in suspended development.................................. 6 421,547 168,985 38,398 --
Projects in early development...................................... 2 -- -- 8,952 --
Other capital projects............................................. NA 35,094 -- -- --
Unassigned equipment............................................... NA -- -- -- 66,073
----------- ----------- ----------- ---------
Total construction and development costs........................... $ 4,321,977 $ 1,783,511 $ 150,179 $ 66,073
=========== =========== =========== =========
- ------------
<FN>
(1) Construction in Progress ("CIP").
(2) We have a total of 11 projects in construction. This includes the 10
projects above that are recorded in CIP and 1 project that is recorded in
investments in power projects. Work and the capitalization of interest on
one of the construction projects has been suspended or delayed due to
current market conditions. The CIP balance on this project was $461.5
million as of December 31, 2004. Subsequent to December 31, 2004, work and
the capitalization of interest on two additional construction projects was
suspended or delayed. Total CIP on these two projects was $683.0 million as
of December 31, 2004.
</FN>
Projects in Construction -- The ten projects in construction are projected
to come on line from March 2005 to November 2007 or later. These projects will
bring on line approximately 4,656 MW of base load capacity (5,264 MW with
peaking capacity). Interest and other costs related to the construction
activities necessary to bring these projects to their intended use are being
capitalized, unless work has been suspended, in which case capitalization of
interest expense is suspended until active construction resumes. At December 31,
2004, the estimated funding requirements to complete these projects, net of
expected project financing proceeds, is approximately $84.6 million.
-33-
Projects in Advanced Development -- There are an additional ten projects in
advanced development. These projects will bring on line approximately 5,307 MW
of base load capacity (6,095 MW with peaking capacity). Interest and other costs
related to the development activities necessary to bring these projects to their
intended use are being capitalized. However, the capitalization of interest has
been suspended on 2 projects for which development activities are substantially
complete but construction will not commence until a power purchase agreement and
financing are obtained. The estimated cost to complete the 10 projects in
advanced development is approximately $3.0 billion. Our current plan is to
project finance these costs as power purchase agreements are arranged.
Suspended Development Projects -- Due to current electric market
conditions, we have ceased capitalization of additional development costs and
interest expense on certain development projects on which work has been
suspended. Capitalization of costs may recommence as work on these projects
resumes, if certain milestones and criteria are met indicating that it is again
highly probable that the costs will be recovered through future operations. As
is true for all projects, the suspended projects are reviewed for impairment
whenever there is an indication of potential reduction in a project's fair
value. Further, if it is determined that it is no longer probable that the
projects will be completed and all capitalized costs recovered through future
operations, the carrying values of the projects would be written down to the
recoverable value. These projects would bring on line approximately 2,956 MW of
base load capacity (3,409 MW with peaking capacity). The estimated cost to
complete these projects is approximately $1.8 billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then, all costs, including interest costs, are expensed. The
projects in early development with capitalized costs relate to two projects and
include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, geothermal resource and facilities
development, as well as software developed for internal use.
Unassigned Equipment -- As of December 31, 2004, we had made progress
payments on four turbines and other equipment with an aggregate carrying value
of $66.1 million. This unassigned equipment is classified on the balance sheet
as other assets, because it is not assigned to specific development and
construction projects. We are holding this equipment for potential use on future
projects. It is possible that some of this unassigned equipment may eventually
be sold, potentially in combination with our engineering and construction
services. For equipment that is not assigned to advanced development or
construction projects, interest is not capitalized.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144 "Accounting for Impairment or Disposal of Long-Lived Assets"
("SFAS No. 144"). We review our unassigned equipment for potential impairment
based on probability-weighted alternatives of utilizing it for future projects
versus selling it. Utilizing this methodology, we do not believe that the
equipment not committed to sale is impaired. However, during the year ended
December 31, 2004, we recorded to the "Equipment cancellation and impairment
cost" line of the Consolidated Statement of Operations $3.2 million in net
losses in connection with equipment sales. During the year ended December 31,
2003, we recorded to the same line $29.4 million in losses in connection with
the sale of four turbines, and we may incur further losses should we decide to
sell more unassigned equipment in the future.
Performance Metrics
In understanding our business, we believe that certain non-GAAP operating
performance metrics are particularly important. These are described below:
o Total deliveries of power. We both generate power that we sell to
third parties and purchase power for sale to third parties in hedging,
balancing and optimization ("HBO") transactions. The former sales are
recorded as electricity and steam revenue and the latter sales are
recorded as sales of purchased power for hedging and optimization. The
volumes in MWh for each are key indicators of our respective levels of
generation and HBO activity and the sum of the two, our total
deliveries of power, is relevant because there are occasions where we
can either generate or purchase power to fulfill contractual sales
commitments. Prospectively beginning October 1, 2003, in accordance
with EITF Issue No. 03-11, certain sales of purchased power for
-34-
hedging and optimization are shown net of purchased power expense for
hedging and optimization in our consolidated statement of operations.
Accordingly, we have also netted HBO volumes on the same basis as of
October 1, 2003, in the table below.
o Average availability and average baseload capacity factor.
Availability represents the percent of total hours during the period
that our plants were available to run after taking into account the
downtime associated with both scheduled and unscheduled outages. The
baseload capacity factor is calculated by dividing (a) total MWh
generated by our power plants (excluding peakers) by the product of
multiplying (b) the weighted average MW in operation during the period
by (c) the total hours in the period. The average baseload capacity
factor is thus a measure of total actual generation as a percent of
total potential generation. If we elect not to generate during periods
when electricity pricing is too low or gas prices too high to operate
profitably, the baseload capacity factor will reflect that decision as
well as both scheduled and unscheduled outages due to maintenance and
repair requirements.
o Average heat rate for gas-fired fleet of power plants expressed in
Btu's of fuel consumed per kilowatt hour ("KWh") generated. We
calculate the average heat rate for our gas-fired power plants
(excluding peakers) by dividing (a) fuel consumed in Btu's by (b) KWh
generated. The resultant heat rate is a measure of fuel efficiency, so
the lower the heat rate, the better. We also calculate a
"steam-adjusted" heat rate, in which we adjust the fuel consumption in
Btu's down by the equivalent heat content in steam or other thermal
energy exported to a third party, such as to steam hosts for our
cogeneration facilities. Our goal is to have the lowest average heat
rate in the industry.
o Average all-in realized electric price expressed in dollars per MWh
generated. Our risk management and optimization activities are
integral to our power generation business and directly impact our
total realized revenues from generation. Accordingly, we calculate the
all-in realized electric price per MWh generated by dividing (a)
adjusted electricity and steam revenue, which includes capacity
revenues, energy revenues, thermal revenues and the spread on sales of
purchased electricity for hedging, balancing, and optimization
activity, by (b) total generated MWh in the period.
o Average cost of natural gas expressed in dollars per millions of Btu's
of fuel consumed. Our risk management and optimization activities
related to fuel procurement directly impact our total fuel expense.
The fuel costs for our gas-fired power plants are a function of the
price we pay for fuel purchased and the results of the fuel hedging,
balancing, and optimization activities by CES. Accordingly, we
calculate the cost of natural gas per millions of Btu's of fuel
consumed in our power plants by dividing (a) adjusted fuel expense
which includes the cost of fuel consumed by our plants (adding back
cost of inter-company gas pipeline costs, which is eliminated in
consolidation), and the spread on sales of purchased gas for hedging,
balancing, and optimization activity by (b) the heat content in
millions of Btu's of the fuel we consumed in our power plants for the
period.
o Average spark spread expressed in dollars per MWh generated. Our risk
management activities focus on managing the spark spread for our
portfolio of power plants, the spread between the sales price for
electricity generated and the cost of fuel. We calculate the spark
spread per MWh generated by subtracting (a) adjusted fuel expense from
(b) adjusted E&S revenue and dividing the difference by (c) total
generated MWh in the period.
o Average plant operating expense per normalized MWh. To assess trends
in electric power plant operating expense ("POX") per MWh, we
normalize the results from period to period by assuming a constant 70%
total company-wide capacity factor (including both baseload and peaker
capacity) in deriving normalized MWh. By normalizing the cost per MWh
with a constant capacity factor, we can better analyze trends and the
results of our program to realize economies of scale, cost reductions
and efficiencies at our electric generating plants. For comparison
purposes we also include POX per actual MWh.
-35-
The table below shows the operating performance metrics for continuing
operations discussed above.
Years Ended December 31,
-------------------------------------------
2004 2003 2002
----------- ----------- -----------
(In thousands)
Operating Performance Metrics;
Total deliveries of power:
MWh generated .................................................................. 87,750 73,553 64,865
HBO and trading MWh sold ....................................................... 51,175 77,232 75,740
----------- ----------- -----------
MWh delivered .................................................................. 138,925 150,785 140,605
=========== =========== ===========
Average availability ............................................................ 92.6% 91.1% 92.3%
Average baseload capacity factor:
Average total MW in operation .................................................. 23,490 18,892 13,146
Less: Average MW of pure peakers ............................................... 2,951 2,672 1,708
----------- ----------- -----------
Average baseload MW in operation ............................................... 20,539 16,220 11,438
Hours in the period ............................................................ 8,784 8,760 8,760
Potential baseload generation (MWh) ............................................ 180,415 142,087 100,197
Actual total generation (MWh) .................................................. 87,750 73,553 64,865
Less: Actual pure peakers' generation (MWh) .................................... 1,453 1,290 979
----------- ----------- -----------
Actual baseload generation (MWh) ............................................... 86,297 72,263 63,886
Average baseload capacity factor ............................................... 47.8% 50.9% 63.8%
Average heat rate for gas-fired power plants (excluding peakers) (Btu's/ KWh):
Not steam adjusted ............................................................. 8,308 8,117 8,015
Steam adjusted ................................................................. 7,169 7,318 7,295
Average all-in realized electric price:
Electricity and steam revenue .................................................. $ 5,297,820 $ 4,393,461 $ 3,031,731
Spread on sales of purchased power for hedging and optimization ................ 165,730 29,003 527,544
----------- ----------- -----------
Adjusted electricity and steam revenue (in thousands) .......................... $ 5,463,550 $ 4,422,464 $ 3,559,275
MWh generated (in thousands) ................................................... 87,750 73,553 64,865
Average all-in realized electric price per MWh ................................. $ 62.26 $ 60.13 $ 54.87
Average cost of natural gas:
Fuel expense (in thousands) ..................................................... $ 3,692,972 $ 2,703,455 $ 1,758,203
Fuel cost elimination .......................................................... 18,028 61,423 14,103
Spread on sales of purchased gas for hedging and optimization .................. (11,587) (41,334) (49,402)
----------- ----------- -----------
Adjusted fuel expense .......................................................... $ 3,699,413 $ 2,723,544 $ 1,722,904
Million Btu's ("MMBtu") of fuel consumed by generating plants (in thousands) 595,395 496,738 453,708
Average cost of natural gas per MMBtu .......................................... $ 6.21 $ 5.48 $ 3.80
MWh generated (in thousands) ................................................... 87,750 73,553 64,865
Average cost of adjusted fuel expense per MWh .................................. $ 42.16 $ 37.03 $ 26.56
Average spark spread:
Adjusted electricity and steam revenue (in thousands) .......................... $ 5,463,550 $ 4,422,464 $ 3,559,275
Less: Adjusted fuel expense (in thousands) ..................................... 3,699,413 2,723,544 1,722,904
----------- ----------- -----------
Spark spread (in thousands) ................................................... $ 1,764,137 $ 1,698,920 $ 1,836,371
MWh generated (in thousands) ................................................... 87,750 73,553 64,865
Average spark spread per MWh ................................................... $ 20.10 $ 23.10 $ 28.31
Average plant operating expense ("POX") per normalized MWh (for comparison
purposes we also include POX per actual MWh):
Average total consolidated MW in operations .................................... 23,490 18,892 13,146
Hours per year ................................................................. 8,784 8,760 8,760
Total potential MWh ............................................................ 206,336 165,494 115,159
Normalized MWh (at 70% capacity factor) ........................................ 144,435 115,846 80,611
Plant operating expense (POX) .................................................. $ 745,704 $ 616,438 $ 483,236
POX per normalized MWh ......................................................... $ 5.16 $ 5.32 $ 5.99
POX per actual MWh ............................................................. $ 8.50 $ 8.38 $ 7.45
-36-
The table below provides additional detail of total mark-to-market
activity. For the years ended December 31, 2004, 2003 and 2002, mark-to-market
activity, net consisted of (dollars in thousands):
Years Ended December 31,
-------------------------------------------
2004 2003 2002
----------- ----------- -----------
(In thousands)
Realized:
Power activity
"Trading Activity" as defined in EITF Issue No. 02-03........................... $ 52,262 $ 52,559 $ 12,175
Other mark-to-market activity(1)................................................ (12,158) (26,059) --
----------- ----------- -----------
Total realized power activity.................................................. $ 40,104 $ 26,500 $ 12,175
=========== =========== ===========
Gas activity
"Trading Activity" as defined in EITF Issue No.
02-03.......................................................................... $ 8,025 $ (2,166) $ 13,915
Other mark-to-market activity(1)................................................ -- -- --
------------ ----------- -----------
Total realized gas activity.................................................... $ 8,025 $ (2,166) $ 13,915
=========== =========== ===========
Total realized activity:
"Trading Activity" as defined in EITF Issue No. 02-03........................... $ 60,287 $ 50,393 $ 26,090
Other mark-to-market activity(1)................................................. (12,158) (26,059) --
----------- ----------- -----------
Total realized activity........................................................ $ 48,129 $ 24,334 $ 26,090
=========== =========== ===========
Unrealized:
Power activity
"Trading Activity" as defined in EITF Issue No. 02-03.......................... $ (18,075) $ (55,450) $ 12,974
Ineffectiveness related to cash flow hedges..................................... 1,814 (5,001) (4,934)
Other mark-to-market activity(1)................................................ (13,591) (1,243) --
----------- ----------- -----------
Total unrealized power activity................................................ $ (29,852) $ (61,694) $ 8,040
=========== =========== ===========
Gas activity
"Trading Activity" as defined in EITF Issue No. 02-03.......................... $ (10,700) $ 7,768 $ (14,792)
Ineffectiveness related to cash flow hedges..................................... 5,827 3,153 2,147
Other mark-to-market activity(1)................................................ -- -- --
----------- ----------- -----------
Total unrealized gas activity.................................................. $ (4,873) $ 10,921 $ (12,645)
=========== =========== ===========
Total unrealized activity:
"Trading Activity" as defined in EITF Issue No. 02-03........................... $ (28,775) $ (47,682) $ (1,818)
Ineffectiveness related to cash flow hedges...................................... 7,641 (1,848) (2,787)
Other mark-to-market activity(1)................................................. (13,591) (1,243) --
----------- ----------- -----------
Total unrealized activity...................................................... $ (34,725) $ (50,773) $ (4,605)
=========== =========== ===========
Total mark-to-market activity:
"Trading Activity" as defined in EITF Issue No. 02-03........................... $ 31,512 $ 2,711 $ 24,272
Ineffectiveness related to cash flow hedges...................................... 7,641 (1,848) (2,787)
Other mark-to-market activity(1)................................................. (25,749) (27,302) --
----------- ----------- -----------
Total mark-to-market activity.................................................. $ 13,404 $ (26,439) $ 21,485
=========== =========== ===========
- ------------
<FN>
(1) Activity related to our assets but does not qualify for hedge
accounting.
</FN>
Strategy
For a discussion of our strategy and management's outlook, see "Item 1 --
Business -- Strategy."
Financial Market Risks
As we are primarily focused on generation of electricity using gas-fired
turbines, our natural physical commodity position is "short" fuel (i.e., natural
gas consumer) and "long" power (i.e., electricity seller). To manage forward
exposure to price fluctuation in these and (to a lesser extent) other
commodities, we enter into derivative commodity instruments as discussed in Item
6. "Business -- Marketing, Hedging, Optimization and Trading Activities."
-37-
The change in fair value of outstanding commodity derivative instruments
from January 1, 2004, through December 31, 2004, is summarized in the table
below (in thousands):
Fair value of contracts outstanding at January 1, 2004................ $ 80,616
Cash losses recognized or otherwise settled during the period(1)...... 38,609
Non-cash losses recognized or otherwise settled during the period(2).. (34,394)
Changes in fair value attributable to new contracts................... (20,910)
Changes in fair value attributable to price movements................. (26,058)
--------
Fair value of contracts outstanding at December 31, 2004(3)......... $ 37,863
========
Realized cash flow from fair value hedges(4).......................... $171,096
- ------------
(1) Recognized (losses) from commodity cash flow hedges of $(97.2) million
(represents realized value of cash flow hedge activity of $(70.2) million
as disclosed in Note 23 of the Notes to Consolidated Financial Statements,
net of non-cash other comprehensive income ("OCI") items relating to
terminated derivatives of $8.1 million, equity method hedges of $10.9
million and discontinued operations of $8.0 million) and realized gains of
$58.6 million on mark-to-market activity, (represents realized value of
mark-to-market activity of $48.3 million, as reported in the Consolidated
Statements of Operations under mark-to-market activities, net of $(10.3)
million of non-cash realized mark-to-market activity).
(2) This represents the non-cash amortization of deferred items embedded in our
derivative assets and liabilities.
(3) Net commodity derivative assets reported in Note 23 of the Notes to
Consolidated Financial Statements.
(4) Not included as part of the roll-forward of net derivative assets and
liabilities because changes in the hedge instrument and hedged item move in
equal and offsetting directions to the extent the fair value hedges are
perfectly effective.
The fair value of outstanding derivative commodity instruments at December
31, 2004, based on price source and the period during which the instruments will
mature, are summarized in the table below (in thousands):
Fair Value Source 2005 2006-2007 2008-2009 After 2009 Total
- ----------------------------------------------------------- -------- --------- --------- ---------- -----------
Prices actively quoted .................................... $ 34,636 $ 57,175 $ -- $ -- $ 91,811
Prices provided by other external sources ................. (46,373) (8,477) 14,678 (30,666) (70,838)
Prices based on models and other valuation methods ........ -- 7,800 9,090 -- 16,890
-------- -------- ------- -------- --------
Total fair value .......................................... $(11,737) $ 56,498 $23,768 $(30,666) $ 37,863
======== ======== ======= ======== ========
Our risk managers maintain fair value price information derived from
various sources in our risk management systems. The propriety of that
information is validated by our Risk Control group. Prices actively quoted
include validation with prices sourced from commodities exchanges (e.g., New
York Mercantile Exchange). Prices provided by other external sources include
quotes from commodity brokers and electronic trading platforms. Prices based on
models and other valuation methods are validated using quantitative methods. See
"Critical Accounting Policies" for a discussion of valuation estimates used
where external prices are unavailable.
The counterparty credit quality associated with the fair value of
outstanding derivative commodity instruments at December 31, 2004, and the
period during which the instruments will mature are summarized in the table
below (in thousands):
Credit Quality (Based on Standard & Poor's
Ratings as of December 31, 2004) 2005 2006-2007 2008-2009 After 2009 Total
- ----------------------------------------------------------- -------- --------- --------- ---------- -----------
Investment grade............................................ $(21,251) $ 56,725 $23,768 $(30,666) $ 28,576
Non-investment grade........................................ 8,676 632 -- -- 9,308
No external ratings......................................... 838 (859) -- -- (21)
--------- -------- ------- -------- --------
Total fair value............................................ $(11,737) $ 56,498 $23,768 $(30,666) $ 37,863
======== ======== ======= ======== ========
-38-
The fair value of outstanding derivative commodity instruments and the fair
value that would be expected after a ten percent adverse price change are shown
in the table below (in thousands):
Fair Value After
10% Adverse
Fair Value Price Change
---------- ----------------
At December 31, 2004:
Electricity................................... $ (51,154) $ (177,534)
Natural gas................................... 89,017 4,505
----------- ------------
Total........................................ $ 37,863 $ (173,029)
=========== ============
Derivative commodity instruments included in the table are those included
in Note 23 of the Notes to Consolidated Financial Statements. The fair value of
derivative commodity instruments included in the table is based on present value
adjusted quoted market prices of comparable contracts. The fair value of
electricity derivative commodity instruments after a 10% adverse price change
includes the effect of increased power prices versus our derivative forward
commitments. Conversely, the fair value of the natural gas derivatives after a
10% adverse price change reflects a general decline in gas prices versus our
derivative forward commitments. Derivative commodity instruments offset the
price risk exposure of our physical assets. None of the offsetting physical
positions are included in the table above.
Price changes were calculated by assuming an across-the-board ten percent
adverse price change regardless of term or historical relationship between the
contract price of an instrument and the underlying commodity price. In the event
of an actual ten percent change in prices, the fair value of our derivative
portfolio would typically change by more than ten percent for earlier forward
months and less than ten percent for later forward months because of the higher
volatilities in the near term and the effects of discounting expected future
cash flows.
The primary factors affecting the fair value of our derivatives at any
point in time are (1) the volume of open derivative positions (MMBtu and MWh),
and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions increased 184%
from December 31, 2003, to December 31, 2004, and the total volume of open power
derivative positions increased 160% for the same period. In that prices for
electricity and natural gas are among the most volatile of all commodity prices,
there may be material changes in the fair value of our derivatives over time,
driven both by price volatility and the changes in volume of open derivative
transactions. Under SFAS No. 133, the change since the last balance sheet date
in the total value of the derivatives (both assets and liabilities) is reflected
either in OCI, net of tax, or in the statement of operations as an item (gain or
loss) of current earnings. As of December 31, 2004, a significant component of
the balance in accumulated OCI represented the unrealized net loss associated
with commodity cash flow hedging transactions. As noted above, there is a
substantial amount of volatility inherent in accounting for the fair value of
these derivatives, and our results during the year ended December 31, 2004, have
reflected this. See Notes 21 and 23 of the Notes to Consolidated Financial
Statements for additional information on derivative activity.
Interest Rate Swaps -- From time to time, we use interest rate swap
agreements to mitigate our exposure to interest rate fluctuations associated
with certain of our debt instruments and to adjust the mix between fixed and
floating rate debt in our capital structure to desired levels. We do not use
interest rate swap agreements for speculative or trading purposes. The following
tables summarize the fair market values of our existing interest rate swap
agreements as of December 31, 2004 (dollars in thousands):
-39-
Variable to Fixed Swaps
Weighted Average Weighted Average
Notional Interest Rate Interest Rate Fair Market
Maturity Date Principal Amount (Pay) (Receive) Value
- ------------------------------------------------------ ---------------- ---------------- ----------------- -----------
2011.................................................. $ 58,178 4.5% 3-month US$LIBOR $ (1,734)
2011.................................................. 291,897 4.5% 3-month US$LIBOR (8,753)
2011.................................................. 209,833 4.4% 3-month US$LIBOR (4,916)
2011.................................................. 41,822 4.4% 3-month US$LIBOR (980)
2011.................................................. 38,479 6.9% 3-month US$LIBOR (4,089)
2012.................................................. 105,840 6.5% 3-month US$LIBOR (11,680)
2016.................................................. 21,120 7.3% 3-month US$LIBOR (3,654)
2016.................................................. 14,080 7.3% 3-month US$LIBOR (2,436)
2016.................................................. 42,240 7.3% 3-month US$LIBOR (7,308)
2016.................................................. 28,160 7.3% 3-month US$LIBOR (4,872)
2016.................................................. 35,200 7.3% 3-month US$LIBOR (6,092)
---------- --- --------
Total............................................... $ 886,849 7.3% $(56,514)
========== === ========
Fixed to Variable Swaps
Weighted Average Weighted Average
Notional Interest Rate Interest Rate Fair Market
Maturity Date Principal Amount (Pay) (Receive) Value
- ------------------------------------------------------ ---------------- ---------------- ----------------- -----------
2011.................................................. $ 100,000 6-month US$LIBOR 8.5% $ (5,406)
2011.................................................. 100,000 6-month US$LIBOR 8.5% (3,699)
2011.................................................. 200,000 6-month US$LIBOR 8.5% (7,740)
2011.................................................. 100,000 6-month US$LIBOR 8.5% (6,508)
---------- --- --------
Total............................................... $ 500,000 8.5% $(23,353)
========== === ========
The fair value of outstanding interest rate swaps and the fair value that
would be expected after a one percent (100 basis points) adverse interest rate
change are shown in the table below (in thousands). Given our net variable to
fixed portfolio position, a 100 basis point decrease would adversely impact our
portfolio as follows:
Fair Value After a 1.0%
(100 Basis Points) Adverse
Net Fair Value as of December 31, 2004 Interest Rate Change
- -------------------------------------------------- -------------------------
$(79,867)......................................... $ (97,567)
Currency Exposure -- We own subsidiary entities in several countries. These
entities generally have functional currencies other than the U.S. dollar. In
most cases, the functional currency is consistent with the local currency of the
host country where the particular entity is located. In certain cases, we and
our foreign subsidiary entities hold monetary assets and/or liabilities that are
not denominated in the functional currencies referred to above. In such
instances, we apply the provisions of SFAS No. 52, "Foreign Currency
Translation," ("SFAS No. 52") to account for the monthly re-measurement gains
and losses of these assets and liabilities into the functional currencies for
each entity. In some cases we can reduce our potential exposures to net income
by designating liabilities denominated in non-functional currencies as hedges of
our net investment in a foreign subsidiary or by entering into derivative
instruments and designating them in hedging relationships against a foreign
exchange exposure. Based on our unhedged exposures at December 31, 2004, the
impact to our pre-tax earnings that would be expected after a 10% adverse change
in exchange rates is shown in the table below (in thousands):
Impact to Pre-Tax Net Income
After 10% Adverse Exchange
Currency Exposure Rate Change
- -------------------------------------------------- ----------------------------
GBP-Euro.......................................... $ (15,982)
$Cdn-$US.......................................... (72,294)
Other............................................. (2,241)
In prior periods, we reported significant unhedged positions and
corresponding foreign currency transaction gains and losses due to our exposure
to changes in the GBP-$US exchange rate. As a result of the sale of Saltend in
July 2005 (see Note 10 of the Notes to Consolidated Financial Statements for
more information), effectively all of our GBP-$US exposure has been eliminated.
-40-
We expect that currency movements will continue to create volatility within our
earnings in future periods, but such volatility will not result from movements
in the GBP-$US exchange rate.
Significant changes in exchange rates will also impact our Cumulative
Translation Adjustment ("CTA") balance when translating the financial statements
of our foreign operations from their respective functional currencies into our
reporting currency, the U.S. dollar. An example of the impact that significant
exchange rate movements can have on our Balance Sheet position occurred in 2004.
During 2004 our CTA increased by approximately $62 million primarily due to a
strengthening of the Canadian dollar and GBP against the U.S. dollar by
approximately 7% each.
Foreign Currency Transaction Gain (Loss)
Year Ended December 31, 2004, Compared to Year Ended December 31, 2003:
The major components of our foreign currency transaction losses from
continuing operations of $41.6 million and $34.5 million, respectively, in 2004
and 2003, respectively, are as follows (amounts in millions):
2004 2003
-------- --------
Gain (Loss) from $Cdn-$US fluctuations:.................. $ (42.8) $ (22.6)
Gain (Loss) from GBP-Euro fluctuations:.................. 0.8 (13.4)
Gain (Loss) from other currency fluctuations:............ 0.5 1.5
------- -------
Total.................................................. $ 41.6 $ 34.5
======= =======
The $Cdn-$US loss for 2004 was driven by two primary factors. First, as a
result of the sale of our Canadian gas assets, we recognized remeasurement
losses due to the fact that the sales proceeds were converted into U.S. dollars
through a series of forward foreign exchange contracts but during September,
October and November, a portion of these converted proceeds were retained by the
$Cdn-denominated entity that sold the assets. During these months, the Canadian
dollar strengthened considerably against the U.S. dollar, creating large
remeasurement losses which did not cease until the balance of the proceeds were
distributed back to the U.S. parent company. Second, also in conjunction with
the sale of our Canadian gas assets, we recognized remeasurement losses during
the third and fourth quarter of 2004 when the Canadian dollar strengthened after
the sale and subsequent repatriation of the proceeds to the U.S. parent company.
The sale and repatriation of funds substantially reduced the degree to which we
could designate our $Cdn-denominated liabilities as hedges against our
investment in Canadian dollar denominated subsidiaries, triggering significant
remeasurement losses as the Canadian dollar strengthened against the U.S.
dollar. This loss was partially offset by remeasurement gains recognized on the
translation of the interest receivable associated with our large intercompany
loan that has been deemed a permanent investment.
The $Cdn-$US loss for 2003 was driven primarily by a significant
strengthening of the Canadian dollar against the U.S. dollar during the first
six months of 2003, at a time when the majority of our $Cdn-$US payable
exposures were not designated as hedges of the net investment in our Canadian
operations. The majority of these payable exposures were created by transactions
that occurred during the fourth quarter of 2002 and the first quarter of 2003.
The losses on these loans were partially offset by remeasurement gains
recognized on the translation of the interest receivable associated with our
large intercompany loan that has been deemed a permanent investment.
During 2004, the Euro weakened slightly against the GBP, triggering
re-measurement gains associated with our Euro-denominated 8 3/8% Senior Notes
Due 2008.
During 2003, the Euro strengthened considerably against the GBP, triggering
re-measurement losses associated with these Senior Notes.
Year Ended December 31, 2003, Compared to Year Ended December 31, 2002:
The major components of our foreign currency transaction losses of $34.5
million and $1.0 million, respectively, in 2003 and 2002, respectively, are as
follows (amounts in millions):
2003 2002
-------- --------
Gain (Loss) from $Cdn-$US fluctuations:.................. $ (22.6) $ (1.3)
Gain (Loss) from GBP-Euro fluctuations:.................. (13.4) 0.3
Gain (Loss) from other currency fluctuations:............ 1.5 --
------- -------
Total.................................................. $ 34.5 $ 1.0
======= =======
-41-
The $Cdn-$US loss for 2003 was driven primarily by a significant
strengthening of the Canadian dollar against the U.S. dollar during the first
six months of 2003, at a time when the majority of our $Cdn-$US payable
exposures were not designated as hedges of the net investment in our Canadian
operations. The majority of these payable exposures were created by transactions
that occurred during the fourth quarter of 2002 and the first quarter of 2003.
The losses on these loans were partially offset by remeasurement gains
recognized on the translation of the interest receivable associated with our
large intercompany loan that has been deemed a permanent investment.
The $Cdn-$US loss for 2002 was significantly smaller than the loss incurred
during 2003, primarily due to a very limited number of $Cdn-$US payable
exposures during the majority of the year. Prior to the fourth quarter of 2002,
we had very few $Cdn-$US transactions subject to re-measurement gains and losses
under the guidance of SFAS No. 52 and as a result of this low transaction
volume, our foreign currency transaction activity was minimal. Additionally, the
$Cdn-$US exchange rate was fairly static during the balance of 2002; the
Canadian dollar strengthened very slightly against the U.S. dollar. The low
volume of transactions combined with very mild exchange rate volatility resulted
in a small financial impact to our Consolidated Statement of Operations.
During 2003, the Euro strengthened considerably against the GBP, triggering
re-measurement losses associated with our Euro-denominated 8 3/8% Senior Notes
Due 2008.
During 2002, the Euro likewise strengthened considerably against the GBP;
however, we effectively mitigated our exposure to the majority of this exchange
rate volatility through a Euro-GBP cross currency swap that was designated as an
effective cash flow hedge against the anticipated Euro-denominated future cash
flows of these Senior Notes in accordance with SFAS No. 133, as amended. The
currency swap was entered into during 2001 in conjunction with the initial
offering of these Senior Notes and was in place for the full balance of 2002.
The swap was subsequently terminated in February, 2003.
Debt Financing -- Because of the significant capital requirements within
our industry, debt financing is often needed to fund our growth. Certain debt
instruments may affect us adversely because of changes in market conditions. We
have used two primary forms of debt which are subject to market risk: (1)
Variable rate construction/project financing and (2) Other variable-rate
instruments. Significant LIBOR increases could have a negative impact on our
future interest expense. Our variable-rate construction/project financing is
primarily through the CalGen floating rate notes, institutional term loans and
revolving credit facility. New borrowings under our $200 million CalGen
revolving credit agreement are used exclusively to fund the construction costs
of CalGen power plants (of which only the Pastoria Energy Center was still in
active construction at December 31, 2004). Other variable-rate instruments
consist primarily of our revolving credit and term loan facilities, which are
used for general corporate purposes. Both our variable-rate construction/project
financing and other variable-rate instruments are indexed to base rates,
generally LIBOR, as shown below.
-42-
The following table summarizes our variable-rate debt, by repayment year,
exposed to interest rate risk as of December 31, 2004. All outstanding balances
and fair market values are shown net of applicable premium or discount, if any
(dollars in thousands):
2005 2006 2007 2008
------- -------- ---------- --------
3-month US $LIBOR weighted average interest rate basis(4)
MEP Pleasant Hill Term Loan, Tranche A ...................................... $ 6,700 $ 7,482 $ 8,132 $ 9,271
Saltend preferred interest .................................................. -- 360,000 -- --
------- -------- ---------- --------
Total of 3-month US $LIBOR rate debt ...................................... 6,700 367,482 8,132 9,271
1-month EURLIBOR weighted average interest rate basis(4)
Thomassen revolving line of credit .......................................... 3,332 -- -- --
------- -------- ---------- --------
Total of 1-month EURLIBOR rate debt ....................................... 3,332 -- -- --
1-month US $LIBOR weighted average interest rate basis(4)
First Priority Secured Floating Rate Notes Due 2009 (CalGen) ................ -- -- 1,175 2,350
------- -------- ---------- --------
Total of 1-month US $LIBOR rate debt ...................................... -- -- 1,175 2,350
6-month US $LIBOR weighted average interest rate basis(4)
Third Priority Secured Floating Rate Notes Due 2011 (CalGen) ................ -- -- -- --
------- -------- ---------- --------
Total of 6-month US $LIBOR rate debt ...................................... -- -- -- --
5-month US $LIBOR weighted average interest rate basis(4)
Riverside Energy Center project financing ................................... 3,685 3,685 3,685 3,685
Rocky Mountain Energy Center project financing .............................. 2,642 2,649 2,649 2,649
------- -------- ---------- --------
Total of 6-month US $LIBOR rate debt ...................................... 6,327 6,334 6,334 6,334
(1)(4)
First Priority Secured Institutional Term Loan Due 2009 (CCFC I) ............ 3,208 3,208 3,208 3,208
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) ........ -- -- -- --
------- -------- ---------- --------
Total of variable rate debt as defined at(1) below ........................ 3,208 3,208 3,208 3,208
(2)(4)
Second Priority Senior Secured Term Loan B Notes Due 2007 ..................... 7,500 7,500 725,625 --
------- -------- ---------- --------
Total of variable rate debt as defined at(2) below ........................ 7,500 7,500 725,625 --
(3)(4)
Second Priority Senior Secured Floating Due 2007 ............................ 5,000 5,000 483,750 --
Blue Spruce Energy Center project financing ................................. 1,875 3,750 3,750 3,750
------- -------- ---------- --------
Total of variable rate debt as defined at(3) below ........................ 6,875 8,750 487,500 3,750
(5)(4)
First Priority Secured Term Loans Due 2009 (CalGen) ........................ -- -- 3,000 6,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen) .............. -- -- -- 3,200
Second Priority Secured Term Loans Due 2010 (CalGen) ....................... -- -- -- 500
------- -------- ---------- --------
Total of variable rate debt as defined at(5) below ...................... -- -- 3,000 9,700
------- -------- ---------- --------
(6)(4)
Island Cogen ................................................................ 9,954 -- -- --
------- -------- ---------- --------
Total of variable rate debt as defined at(6) below ........................ 9,954 -- -- --
(6)(4)
Contra Costa ................................................................ 168 175 182 190
------- -------- ---------- --------
Total of variable rate debt as defined at(6) below ........................ 168 175 182 190
------- -------- ---------- --------
Grand total variable-rate debt instruments .............................. $44,064 $393,449 $1,235,156 $ 34,803
======= ======== ========== ========
-43-
Fair Value
December 31,
2009 Thereafter 2004(7)
---------- ---------- -----------
3-month US $LIBOR weighted average interest rate basis(4)
MEP Pleasant Hill Term Loan, Tranche A ...................................... $ 9,433 $ 85,802 $ 126,820
Saltend preferred interest .................................................. -- -- 360,000
---------- ---------- -----------
Total of 3-month US $LIBOR rate debt ...................................... 9,433 85,802 486,820
1-month EURLIBOR weighted average interest rate basis(4)
Thomassen revolving line of credit ............................................ -- -- 3,332
---------- ---------- -----------
Total of 1-month EURLIBOR rate debt ....................................... -- -- 3,332
1-month US $LIBOR weighted average interest rate basis(4)
First Priority Secured Floating Rate Notes Due 2009 (CalGen) .................. 231,475 -- 235,000
---------- ---------- -----------
Total of 1-month US $LIBOR rate debt ...................................... 231,475 -- 235,000
6-month US $LIBOR weighted average interest rate basis(4)
Third Priority Secured Floating Rate Notes Due 2011 (CalGen) .................. -- 680,000 680,000
---------- ---------- -----------
Total of 6-month US $LIBOR rate debt ...................................... -- 680,000 680,000
5-month US $LIBOR weighted average interest rate basis(4)
Riverside Energy Center project financing ..................................... 3,685 350,075 368,500
Rocky Mountain Energy Center project financing .............................. 2,649 251,662 264,900
---------- ---------- -----------
Total of 6-month US $LIBOR rate debt ...................................... 6,334 601,737 633,400
(1)(4)
First Priority Secured Institutional Term Loan Due 2009 (CCFC I) ............ 365,350 -- 378,182
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) ........ -- 408,568 408,568
---------- ---------- -----------
Total of variable rate debt as defined at(1) below ........................ 365,350 408,568 786,750
(2)(4)
Second Priority Senior Secured Term Loan B Notes Due 2007 ................... -- -- 677,672
---------- ---------- -----------
Total of variable rate debt as defined at(2) below ........................ -- -- 677,672
(3)(4)
Second Priority Senior Secured Floating Due 2007 ............................ -- -- 449,313
Blue Spruce Energy Center project financing ................................. 3,750 81,397 98,272
---------- ---------- -----------
Total of variable rate debt as defined at(3) below ........................ 3,750 81,397 547,585
(5)(4)
First Priority Secured Term Loans Due 2009 (CalGen) ......................... 591,000 -- 600,000
Second Priority Secured Floating Rate Notes Due 2010 (CalGen) ............... 6,400 622,039 631,639
Second Priority Secured Term Loans Due 2010 (CalGen) ........................ 1,000 97,194 98,694
---------- ---------- -----------
Total of variable rate debt as defined at(5) below ...................... 598,400 719,233 1,330,333
---------- ---------- -----------
(6)(4)
Island Cogen .................................................................. -- -- 9,954
---------- ---------- -----------
Total of variable rate debt as defined at(6) below ........................ -- -- 9,954
(6)(4)
Contra Costa .................................................................. 197 1,364 2,276
---------- ---------- -----------
Total of variable rate debt as defined at(6) below ........................ 197 1,364 2,276
---------- ---------- -----------
Grand total variable-rate debt instruments .............................. $1,214,939 $2,578,101 $ 5,393,122
========== ========== ===========
- ------------
<FN>
(1) British Bankers Association LIBOR Rate for deposit in US dollars for a
period of six months.
(2) U.S. prime rate in combination with the Federal Funds Effective Rate.
(3) British Bankers Association LIBOR Rate for deposit in US dollars for a
period of three months.
(4) Actual interest rates include a spread over the basis amount.
(5) Choice of 1-month US $LIBOR, 2-month US $LIBOR, 3-month US $LIBOR, 6-month
US $LIBOR, 12-month US $LIBOR or a base rate.
(6) Bankers Acceptance Rate.
(7) Fair value equals carrying value, with the exception of the Second-Priority
Senior Secured Term B Loans Due 2007 and Second-Priority Senior Secured
Floating Rate Notes Due 2007 which are shown at quoted trading values as of
December 31, 2004.
</FN>
-44-
Construction/Project Financing Facilities -- See Note 16 of the Notes to
Consolidated Financial Statements for information on our construction/project
financing.
Application of Critical Accounting Policies
Our financial statements reflect the selection and application of
accounting policies which require management to make significant estimates and
judgments. See Note 2 of the Notes to Consolidated Financial Statements,
"Summary of Significant Accounting Policies." We believe that the following
reflect the more critical accounting policies that currently affect our
financial condition and results of operations.
Fair Value of Energy Marketing and Risk Management Contracts and Derivatives
Accounting for derivatives at fair value requires us to make estimates
about future prices during periods for which price quotes are not available from
sources external to us. As a result, we are required to rely on internally
developed price estimates when external quotes are unavailable. We derive our
future price estimates, during periods, where external price quotes are
unavailable, based on extrapolation of prices from prior periods where external
price quotes are available. We perform this extrapolation using liquid and
observable market prices and extending those prices to an internally generated
long-term price forecast based on a generalized equilibrium model.
Credit Reserves
In estimating the fair value of our derivatives, we must take into account
the credit risk that our counterparties will not have the financial wherewithal
to honor their contract commitments.
In establishing credit risk reserves we take into account historical
default rate data published by the rating agencies based on the credit rating of
each counterparty where we have realization exposure, as well as other published
data and information.
Liquidity Reserves
We value our forward positions at the mid-market price, or the price in the
middle of the bid-ask spread. This creates a risk that the value reported by us
as the fair value of our derivative positions will not represent the realizable
value or probable loss exposure of our derivative positions if we are unable to
liquidate those positions at the mid-market price. Adjusting for this liquidity
risk states our derivative assets and liabilities at their most probable value.
We use a two-step quantitative and qualitative analysis to determine our
liquidity reserve.
In the first step we quantitatively derive an initial liquidity reserve
assessment applying the following assumptions in calculating the initial
liquidity reserve assessment: (1) where we have the capability to cover physical
positions with our own assets, we assume no liquidity reserve is necessary
because we will not have to cross the bid-ask spread in covering the position;
(2) we record no reserve against our hedge positions because a high likelihood
exists that we will hold our hedge positions to maturity or cover them with our
own assets; and (3) where reserves are necessary, we base the reserves on the
spreads observed using broker quotes as a starting point.
Using these assumptions, we calculate the net notional volume exposure at
each location by commodity and multiply the result by one half of the bid-ask
spread.
The second step involves a qualitative analysis where the initial
assessment may be adjusted for qualitative factors such as liquidity spreads
observed through recent trading activity, strategies for liquidating open
positions, and imprecision in or unavailability of broker quotes due to market
illiquidity. Using this quantitative and qualitative information, we estimate
the amount of probable liquidity risk exposure to us and we record this estimate
as a liquidity reserve.
Accounting for Commodity Contracts
Commodity contracts are evaluated to determine whether the contract is (1)
accounted for as a lease (2) accounted for as a derivative (3) or accounted for
as an executory contract and additionally whether the financial statement
presentation is gross or net.
Accounting for Leases -- We account for commodity contracts as leases per
SFAS No. 13 , "Accounting for Leases," ("SFAS No. 13") and EITF Issue No. 01-08,
"Determining Whether an Arrangement Contains a Lease," ("EITF Issue No. 01-08").
EITF Issue No. 01-08 clarifies the requirements of identifying whether an
arrangement should be accounted for as a lease at its inception. The guidance in
the consensus is designed to broaden the scope of arrangements, such as power
purchase agreements, accounted for as leases. EITF Issue No. 01-08 requires both
-45-
parties to an arrangement to determine whether a service contract or similar
arrangement is, or includes, a lease within the scope of SFAS No. 13. The
consensus is being applied prospectively to arrangements agreed to, modified, or
acquired in business combinations on or after July 1, 2003. Prior to adopting
EITF Issue No. 01-08, we had accounted for certain contractual arrangements as
leases under existing industry practices, and the adoption of EITF Issue No.
01-08 did not materially change our accounting for leases. Per SFAS No. 13,
operating leases with minimum lease rentals which vary over time must be
levelized over the term of the contract. We levelize these contracts on a
straight-line basis. See Note 25 for additional information on our operating
leases. For income statement presentation purposes, income from arrangements
accounted for as leases is classified within electricity and steam revenue in
our consolidated statements of operations.
Accounting for Derivatives -- On January 1, 2001, we adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities --
Deferral of the Effective Date of FASB Statement No. 133 -- an Amendment of FASB
Statement No. 133," SFAS No. 138, "Accounting for Certain Derivative Instruments
and Certain Hedging Activities -- an Amendment of FASB Statement No. 133," and
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities." We currently hold six classes of derivative instruments that are
impacted by the new pronouncement -- foreign currency swaps, interest rate
swaps, forward interest rate agreements, commodity financial instruments,
commodity contracts, and physical options.
Consistent with the requirements of SFAS No. 133, we evaluate all of our
contracts to determine whether or not they qualify as derivatives under the
accounting pronouncements. For a given contract, there are typically three steps
we use to determine its proper accounting treatment. First, based on the terms
and conditions of the contract, as well as the applicable guidelines established
by SFAS No. 133, we identify the contract as being either a derivative or
non-derivative contract. Second, if the contract is not a derivative, we account
for it as an executory contract. Alternatively, if the contract does qualify as
a derivative under the guidance of SFAS No. 133, we evaluate whether or not it
qualifies for the "normal" purchases and sales exception (as described below).
If the contract qualifies for the exception, we may elect to apply the normal
exception and account for as an executory contract. Finally, if the contract is
a derivative, we apply the accounting treatment required by SFAS No. 133, which
is outlined below in further detail.
Normal Purchases and Sales
When we elect normal purchases and sales treatment, as defined by paragraph
10b. of SFAS No. 133 and amended by SFAS No. 138 and SFAS No. 149, the normal
contracts are exempt from SFAS No. 133 accounting treatment. As a result, these
contracts are not required to be recorded on the balance sheet at their fair
values and any fluctuations in these values are not required to be reported
within earnings. Probability of physical delivery from our generation plants, in
the case of electricity sales, and to our generation plants, in the case of
natural gas contracts, is required over the life of the contract within
reasonable tolerances.
Two of our contracts that had been accounted for as normal contracts were
subject to the special transition adjustment for their estimated future economic
benefits upon adoption of DIG Issue No. C20, and we amortize the corresponding
asset recorded upon adoption of DIG Issue No. C20 through a charge to earnings.
Accordingly on October 1, 2003, the date we adopted DIG Issue No. C20, we
recorded other current assets and other assets of approximately $33.5 million
and $259.9 million, respectively, and a cumulative effect of a change in
accounting principle of approximately $181.9 million, net of $111.5 million of
tax. For periods subsequent to October 1, 2003, we again account for these two
contracts as normal purchases and sales under the provisions of DIG Issue No.
C20.
Fair Value Hedges
As further defined in SFAS No. 133, fair value hedge transactions hedge the
exposure to changes in the fair value of either all or a specific portion of a
recognized asset or liability or of an unrecognized firm commitment. The
accounting treatment for fair value hedges requires reporting both the changes
in fair values of a hedged item (the underlying risk) and the hedging instrument
(the derivative designated to offset the underlying risk) on both the balance
sheet and the income statement. On that basis, when a firm commitment is
associated with a hedge instrument that attains 100% effectiveness (under the
effectiveness criteria outlined in SFAS No. 133), there is no net earnings
impact because the earnings caused by the changes in fair value of the hedged
item will move in an equal, but opposite, amount as the earnings caused by the
changes in fair value of the hedging instrument. In other words, the earnings
volatility caused by the underlying risk factor will be neutralized because of
the hedge. For example, if we want to manage the price-induced fair value risk
(i.e. the risk that market electric rates will rise, making a fixed price
contract less valuable) associated with all or a portion of a fixed price power
-46-
sale that has been identified as a "normal" transaction (as described above), we
might create a fair value hedge by purchasing fixed price power. From that date
and time forward until delivery, the change in fair value of the hedged item and
hedge instrument will be reported in earnings with asset/liability offsets on
the balance sheet. If there is 100% effectiveness, there is no net earnings
impact. If there is less than 100% effectiveness, the fair value change of the
hedged item (the underlying risk) and the hedging instrument (the derivative)
will likely be different and the "ineffectiveness" will result in a net earnings
impact.
Cash Flow Hedges
As further defined in SFAS No. 133, cash flow hedge transactions hedge the
exposure to variability in expected future cash flows (i.e., in our case, the
price variability of forecasted purchases of gas and sales of power, as well as
interest rate and foreign exchange rate exposure). In the case of cash flow
hedges, the hedged item (the underlying risk) is generally unrecognized (i.e.,
not recorded on the balance sheet prior to delivery), and any changes in this
fair value, therefore, will not be recorded within earnings. Conceptually, if a
cash flow hedge is effective, this means that a variable, such as movement in
power prices, has been effectively fixed, so that any fluctuations will have no
net result on either cash flows or earnings. Therefore, if the changes in fair
value of the hedged item are not recorded in earnings, then the changes in fair
value of the hedging instrument (the derivative) must also be excluded from the
income statement, or else a one-sided net impact on earnings will be reported,
despite the fact that the establishment of the effective hedge results in no net
economic impact. To prevent such a scenario from occurring, SFAS No. 133
requires that the fair value of a derivative instrument designated as a cash
flow hedge be recorded as an asset or liability on the balance sheet, but with
the offset reported as part of other comprehensive income, to the extent that
the hedge is effective. Similar to fair value hedges, any ineffectiveness
portion will be reflected in earnings.
Undesignated Derivatives
The fair values and changes in fair values of undesignated derivatives are
recorded in earnings, with the corresponding offsets recorded as derivative
assets or liabilities on the balance sheet. We have the following types of
undesignated transactions:
o transactions executed at a location where we do not have an associated
natural long (generation capacity) or short (fuel consumption
requirements) position of sufficient quantity for the entire term of
the transaction (e.g., power sales where we do not own generating
assets or intend to acquire transmission rights for delivery from
other assets for any portion of the contract term), and
o transactions executed with the intent to profit from short-term price
movements, and
o discontinuance (de-designation) of hedge treatment prospectively
consistent with paragraphs 25 and 32 of SFAS No. 133. In circumstances
where we believe the hedge relationship is no longer necessary, we
will remove the hedge designation and close out the hedge positions by
entering into an equal and offsetting derivative position.
Prospectively, the two derivative positions should generally have no
net earnings impact because the changes in their fair values are
offsetting.
o any other transactions that do not qualify for hedge accounting
Our Mark-to-Market Activity includes realized settlements of and unrealized
mark-to-market gains and losses on both power and gas derivative instruments not
designated as cash flow hedges, including those held for trading purposes. Our
gains and losses due to ineffectiveness on hedging instruments are also included
in unrealized mark-to-market gains and losses. We present trading activity net
in accordance with EITF Issue No. 02-03.
Accounting for Executory Contracts -- Where commodity contracts do not
qualify as leases or derivatives, the contracts are classified as executory
contracts. These contracts apply traditional accrual accounting treatment unless
the revenue must be levelized per EITF Issue No. 91-06, "Revenue Recognition of
Long Term Power Sales Contracts." We currently account for one commodity
contract under EITF 91-06 which is levelized over the term of the agreement.
Accounting for Financial Statement Presentation -- Where our derivative
instruments are subject to a netting agreement and the criteria of FIN 39
"Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB
Opinion No. 10 and SFAS No. 105)" are met, we present the derivative assets and
liabilities on a net basis in our balance sheet. We chose this method of
presentation because it is consistent with the way related mark-to-market gains
and losses on derivatives are recorded in Consolidated Statements of Operations
and within Other Comprehensive Income.
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We account for certain of our power sales and purchases on a net basis
under EITF Issue No. 03-11 "Reporting Realized Gains and Losses on Derivative
Instruments That Are Subject to SFAS No. 133 and Not "Held for Trading Purposes'
As Defined in EITF Issue No. 02-03: "Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities' ("EITF Issue No. 03-11"), which we
adopted on a prospective basis on October 1, 2003. Transactions with either of
the following characteristics are presented net in our Consolidated Financial
Statements: (1) transactions executed in a back-to-back buy and sale pair,
primarily because of market protocols; and (2) physical power purchase and sale
transactions where our power schedulers net the physical flow of the power
purchase against the physical flow of the power sale (or "book out" the physical
power flows) as a matter of scheduling convenience to eliminate the need for
actual power delivery. These book out transactions may occur with the same
counterparty or between different counterparties where we have equal but
offsetting physical purchase and delivery commitments.
Accounting for Long-Lived Assets
Plant Useful Lives
Property, plant and equipment is stated at cost. The cost of renewals and
betterments that extend the useful life of property, plant and equipment are
also capitalized. Depreciation is recorded utilizing the straight line method
over the estimated original composite useful life, generally 35 years for
baseload power plants and 40 years for peaking facilities, exclusive of the
estimated salvage value, typically 10%.
Impairment of Long-Lived Assets, Including Intangibles
We evaluate long-lived assets, such as property, plant and equipment,
equity method investments, patents, and specifically identifiable intangibles,
when events or changes in circumstances indicate that the carrying value of such
assets may not be recoverable. Discussion of the impairment of oil and gas
assets is covered under "Oil and Gas Property Valuations" below. Factors which
could trigger an impairment include determination that a suspended project is
not completed, significant underperformance relative to historical or projected
future operating results, significant changes in the manner of our use of the
acquired assets or the strategy for our overall business and significant
negative industry or economic trends. Certain of our generating assets are
located in regions with depressed demand and market spark spreads. Our forecasts
assume that spark spreads will increase in future years in these regions as the
supply and demand relationships improve.
The determination of whether an impairment of a power plant has occurred is
based on an estimate of undiscounted cash flows attributable to the assets, as
compared to the carrying value of the assets. The significant assumptions that
we use in our undiscounted future cash flow estimates include the probability of
completion of assets in development or construction the future supply and demand
relationships for electricity and natural gas, and the expected pricing for
those commodities and the resultant spark spreads in the various regions where
we generate. If an impairment has occurred, the amount of the impairment loss
recognized would be determined by estimating the fair value of the assets and
recording a loss if the fair value was less than the book value. For equity
method investments and assets identified as held for sale, the book value is
compared to the estimated fair value to determine if an impairment loss is
required. For equity method investments, we would record a loss when the decline
in value is other than temporary.
Our assessment regarding the existence of impairment factors is based on
market conditions, operational performance and legal factors of our businesses.
Our review of factors present and the resulting appropriate carrying value of
our intangibles, and other long-lived assets are subject to judgments and
estimates that management is required to make. Future events could cause us to
conclude that impairment indicators exist and that our intangibles, and other
long-lived assets might be impaired.
Turbine Impairment Charges
A significant portion of our overall cost of constructing a power plant is
the cost of the gas turbine-generators, steam turbine-generators and related
equipment (collectively the "turbines"). The turbines are ordered primarily from
three large manufacturers under long-term, build to order contracts. Payments
are generally made over a two to four year period for each turbine. The turbine
prepayments are included as a component of construction-in-progress if the
turbines are assigned to specific projects probable of being built, and interest
is capitalized on such costs. Turbines assigned to specific projects are not
evaluated for impairment separately from the project as a whole. Prepayments for
turbines that are not assigned to specific projects that are probable of being
built are carried in other assets, and interest is not capitalized on such
costs. Additionally, our commitments relating to future turbine payments are
discussed in Note 25 of the Notes to Consolidated Financial Statements.
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To the extent that there are more turbines on order than are allocated to
specific construction projects, we determine the probability that new projects
will be initiated to utilize the turbines or that the turbines will be resold to
third parties. The completion of in progress projects and the initiation of new
projects are dependent on our overall liquidity and the availability of funds
for capital expenditures.
In assessing the impairment of turbines, we must determine both the
realizability of the progress payments to date that have been capitalized, as
well as the probability that at future decision dates, we will cancel the
turbines and apply the prepayments to the cancellation charge, or will proceed
and pay the remaining progress payments in accordance with the original payment
schedule.
We apply SFAS No. 5, "Accounting for Contingencies" to evaluate potential
future cancellation obligations. We apply SFAS No. 144 to evaluate turbine
progress payments made to date for, and the carrying value of, delivered
turbines not assigned to projects. At the reporting date, if we believe that it
is probable that we will elect the cancellation provisions on future decision
dates, then the expected future termination payment is also expensed.
Oil and Gas Property Valuations
On July 7, 2005, we, along with our subsidiaries, Calpine Gas Holdings LLC
and Calpine Fuels Corporation, sold substantially all of our remaining domestic
oil and gas assets to Rosetta Resources Inc. for $1.05 billion, less certain
transaction fees and expenses. See Note 10 of the Notes to Consolidated
Financial Statements for more information on this transaction. The assets
underlying the transaction qualified as discontinued operations in the three
months ended June 30, 2005. The following information relates to the historical
accounting for our oil and gas properties.
Successful Efforts Method of Accounting. We follow the successful efforts
method of accounting for oil and natural gas activities. Under the successful
efforts method, lease acquisition costs and all development costs are
capitalized. Exploratory drilling costs are capitalized until the results are
determined. If proved reserves are not discovered, the exploratory drilling
costs are expensed. Other exploratory costs are expensed as incurred. Interest
costs related to financing major oil and gas projects in progress are
capitalized until the projects are evaluated, or until the projects are
substantially complete and ready for their intended use if the projects are
evaluated as successful.
The successful efforts method of accounting relies on management's judgment
in the designation of wells as either exploratory or developmental, which
determines the proper accounting treatment of costs incurred. During 2004 we
drilled 75 (net 39.3) development wells and 24 (net 14.5) exploratory wells, of
which 71 (net 35.8) development and 21 (net 13.0) exploration were successful.
Our operational results may be significantly impacted if we decide to drill in a
new exploratory area, which will result in increased seismic costs and
potentially increased dry hole costs if the wells are determined to be not
successful.
Successful Efforts Method of Accounting v. Full Cost Method of Accounting.
Under the successful efforts method, unsuccessful exploration well cost,
geological and geophysical costs, delay rentals, and general and administrative
expenses directly allocable to acquisition, exploration, and development
activities are charged to exploration expense as incurred; whereas, under the
full cost method these costs are capitalized and amortized over the life of the
reserves.
A significant sale (usually multiple fields) would have to occur before a
gain or loss would be recognized under the full cost method. However, under the
successful efforts method, when only an entire cost center (generally a field)
is sold, a gain or loss is recognized.
For impairment evaluation purposes, successful efforts requires that
individual assets are grouped for impairment purposes at the lowest level for
which there are identifiable cash flows, which is generally on a field-by-field
basis. Under full cost impairment review, all properties in the depreciation,
depletion and amortization pools based on geography are assessed against a
ceiling based on discounted cash flows, with certain adjustments.
Though successful efforts and full cost methods are both acceptable under
GAAP, successful efforts is used by most major companies due to such method
being more reflective of current operating results due to the expensing of
certain exploration activities.
Oil and Gas Reserves. The process of estimating quantities of proved
developed and proved undeveloped crude oil and natural gas reserves is very
complex, requiring significant subjective decisions in the evaluation of all
available geological, engineering and economic data for each reservoir.
Estimates of economically recoverable oil and gas reserves and future net cash
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flows depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effect of governmental regulations, operating and
workover costs, severance taxes and development costs, all of which may vary
considerably from actual results. Any significant variance in the assumptions
could materially affect the estimated quantity and value of the reserves, which
could affect the carrying value of our oil and gas properties and/or the rate of
depletion of such properties.
We based our estimates of proved developed and proved undeveloped reserves
as of December 31, 2004, 2003 and 2002, on estimates made by Netherland, Sewell
& Associates, Inc. for reserves in the United States, and by Gilbert Laustsen
Jung Associates Ltd. for 2003 and 2002 reserves in Canada, both independent
petroleum engineering firms.
Impairment of Oil and Gas Properties. Prior to the sale of our remaining
oil and gas assets in July 2005, we reviewed our oil and gas properties
periodically (at least annually) to determine if impairment of such properties
was necessary. Property impairments may occur if a field discovers lower than
anticipated reserves, reservoirs produce below original estimates or if
commodity prices fall below a level that significantly affects anticipated
future cash flows on the property. Proved oil and gas property values were
reviewed when circumstances suggest the need for such a review and, if required,
the proved properties were written down to their estimated fair value based on
proved reserves and other market factors. Unproved properties were reviewed
quarterly to determine if there had been impairment of the carrying value, with
any such impairment charged to expense in the current period. During the year
ended December 31, 2004, we recorded $202.1 million in impairment charges, which
is included in discontinued operations in the Consolidated Statement of
Operations related to reduced proved reserve projections based on the year end
independent engineers report. Prior to the commitment to a plan of divestiture
of our remaining oil and gas assets during the three months ended June 30, 2005,
this impairment charge was included in gross profit. This impairment is
discussed further in Note 4 of the Notes to Consolidated Financial Statements.
Capitalized Interest
We capitalize interest using two methods: (1) capitalized interest on funds
borrowed for specific construction projects and (2) capitalized interest on
general corporate funds. For capitalization of interest on specific funds, we
capitalize the interest cost incurred related to debt entered into for specific
projects under construction or in the advanced stage of development. The
methodology for capitalizing interest on general funds, consistent with
paragraphs 13 and 14 of SFAS No. 34, "Capitalization of Interest Cost," begins
with a determination of the borrowings applicable to our qualifying assets. The
basis of this approach is the assumption that the portion of the interest costs
that are capitalized on expenditures during an asset's acquisition period could
have been avoided if the expenditures had not been made. This methodology takes
the view that if funds are not required for construction then they would have
been used to pay off other debt. We use our best judgment in determining which
borrowings represent the cost of financing the acquisition of the assets. The
primary debt instruments included in the rate calculation of interest incurred
on general corporate funds have been our Senior Notes, our term loan facilities
and our secured working capital revolving credit facility with adjustments made
as debt is retired or new debt is issued. The interest rate is derived by
dividing the total interest cost by the average borrowings. This weighted
average interest rate is applied to our average qualifying assets in excess of
specific debt on which interest is capitalized. To qualify for interest
capitalization, we must continue to make significant progress on the
construction of the assets. See Note 4 of the Notes to Consolidated Financial
Statements for additional information about the capitalization of interest
expense.
Accounting for Income and Other Taxes
To arrive at our worldwide income tax provision and other tax balances,
significant judgment is required. In the ordinary course of a global business,
there are many transactions and calculations where the ultimate tax outcome is
uncertain. Some of these uncertainties arise as a consequence of the treatment
of capital assets, financing transactions, multistate taxation of operations and
segregation of foreign and domestic income and expense to avoid double taxation.
Although we believe that our estimates are reasonable, no assurance can be given
that the final tax outcome of these matters will not be different than that
which is reflected in our historical tax provisions and accruals. Such
differences could have a material impact on our income tax provision, other tax
accounts and net income in the period in which such determination is made.
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We record a valuation allowance to reduce our deferred tax assets to the
amount of future tax benefit that is more likely than not to be realized. While
we have considered future taxable income and ongoing prudent and feasible tax
planning strategies in assessing the need for the valuation allowance, there is
no assurance that the valuation allowance would not need to be increased to
cover additional deferred tax assets that may not be realizable. Any increase in
the valuation allowance could have a material adverse impact on our income tax
provision and net income in the period in which such determination is made.
We provide for United States income taxes on the earnings of foreign
subsidiaries unless they are considered permanently invested outside the United
States. At December 31, 2004, we had no cumulative undistributed earnings of
foreign subsidiaries.
Our effective income tax rates for continuing operations were 35.9%, 56.8%
and 90.1% in fiscal 2004, 2003 and 2002, respectively. The effective tax rate in
all periods is the result of profits (losses) Calpine Corporation and its
subsidiaries earned in various tax jurisdictions, both foreign and domestic,
that apply a broad range of income tax rates. The provision for income taxes
differs from the tax computed at the federal statutory income tax rate due
primarily to state taxes, tax credits, other permanent differences and earnings
considered as permanently reinvested in foreign operations. Future effective tax
rates could be adversely affected if earnings are lower than anticipated in
countries where we have lower statutory rates, if unfavorable changes in tax
laws and regulations occur, or if we experience future adverse determinations by
taxing authorities after any related litigation. Our foreign taxes at rates
other than statutory include the benefit of cross border financings as well as
withholding taxes and foreign valuation allowance.
Under SFAS No. 109, "Accounting for Income Taxes," deferred tax assets and
liabilities are determined based on differences between the financial reporting
and tax basis of assets and liabilities, and are measured using enacted tax
rates and laws that will be in effect when the differences are expected to
reverse. SFAS No. 109 provides for the recognition of deferred tax assets if
realization of such assets is more likely than not. Based on the weight of
available evidence, we have provided a valuation allowance against certain
deferred tax assets. The valuation allowance was based on the historical
earnings patterns within individual tax jurisdictions that make it uncertain
that we will have sufficient income in the appropriate jurisdictions to realize
the full value of the assets. We will continue to evaluate the realizability of
the deferred tax assets on a quarterly basis.
At December 31, 2004, we had credit carryforwards of $50.4 million. These
credits relate to Energy Credits, Research and Development Credits, Alternative
Minimum Tax Credits and other miscellaneous state credits. The net operating
loss carryforward consists of federal and state carryforwards of approximately
$2.3 billion which expire between 2017 and 2019. The federal and state net
operating loss carryforwards available are subject to limitations on their
annual usage. We also have loss carryforwards in certain foreign subsidiaries,
resulting in tax benefits of approximately $152 million, the majority of which
expire by 2008. We provided a valuation allowance on certain state and foreign
tax jurisdiction deferred tax assets to reduce the gross amount of these assets
to the extent necessary to result in an amount that is more likely than not of
being realized. Realization of the deferred tax assets and net operating loss
carryforwards is dependent, in part, on generating sufficient taxable income
prior to expiration of the loss carryforwards. The amount of the deferred tax
asset considered realizable, however, could be reduced in the near term if
estimates of future taxable income during the carryforward period are reduced.
Variable Interest Entities and Primary Beneficiary
In determining whether an entity is a variable interest entity ("VIE") and
whether or not we are the Primary Beneficiary, we use significant judgment
regarding the adequacy of an entity's equity relative to maximum expected
losses, amounts and timing of estimated cash flows, discount rates and the
probability of achieving a specific expected future cash flow outcome for
various cash flow scenarios. Due to the long-term nature of our investment in a
VIE and its underlying assets, our estimates of the probability-weighted future
expected cash flow outcomes are complex and subjective, and are based, in part,
on our assessment of future commodity prices based on long-term supply and
demand forecasts for electricity and natural gas, operational performance of the
underlying assets, legal and regulatory factors affecting our industry,
long-term interest rates and our current credit profile and cost of capital. As
a result of applying the complex guidance outlined in FIN 46-R, we may be
required to consolidate assets we do not legally own and liabilities that we are
not legally obligated to satisfy. Also, future changes in a VIE's legal or
capital structure may cause us to reassess whether or not we are the Primary
Beneficiary and may result in our consolidation or deconsolidation of that
entity.
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We adopted FIN 46-R for our equity method joint ventures and operating
lease arrangements containing fixed price purchase options, our wholly owned
subsidiaries that are subject to long-term power purchase agreements and tolling
arrangements and our wholly owned subsidiaries that have issued mandatorily
redeemable non-controlling preferred interests as of March 31, 2004, and for our
investments in SPEs as of December 31, 2003.
Joint Venture Investments and Operating Leases with Fixed Price Options
On application of FIN 46-R, we evaluated our investments in joint venture
investments and operating lease arrangements containing fixed price purchase
options and concluded that, in some instances, these entities were VIEs.
However, in these instances, we were not the Primary Beneficiary, as we would
not absorb a majority of these entities' expected variability. An enterprise
that holds a significant variable interest in a VIE is required to make certain
disclosures regarding the nature and timing of its involvement with the VIE and
the nature, purpose, size and activities of the VIE. The fixed price purchase
options under our operating lease arrangements were not considered significant
variable interests. However, the joint ventures in which we invested, and which
did not qualify for the definition of a business scope exception outlined in
paragraph 4(h) of FIN 46-R, were considered significant variable interests and
the required disclosures have been made in Note 7 of the Notes to Consolidated
Financial Statements for these joint venture investments.
Significant Long-Term Power Sales and Tolling Agreements
An analysis was performed for our wholly owned subsidiaries with
significant long-term power sales or tolling agreements. Certain of our 100%
owned subsidiaries were deemed to be VIEs by virtue of the power sales and
tolling agreements which meet the definition of a variable interest under FIN
46-R. However, in all cases, we absorbed a majority of the entity's variability
and continue to consolidate our wholly owned subsidiaries. As part of our
quantitative assessment, a fair value methodology was used to determine whether
we or the power purchaser absorbed the majority of the subsidiary's variability.
As part of our analysis, we qualitatively determined that power sales or tolling
agreements with a term for less than one-third of the facility's remaining
useful life or for less than 50% of the entity's capacity would not cause the
power purchaser to be the Primary Beneficiary, due to the length of the economic
life of the underlying assets. Also, power sales and tolling agreements meeting
the definition of a lease under EITF Issue No. 01-08, "Determining Whether an
Arrangement Contains a Lease," were not considered variable interests, since
lease payments create rather than absorb variability, and therefore, do not meet
the definition of a variable interest.
Preferred Interests issued from Wholly-Owned Subsidiaries
A similar analysis was performed for our wholly owned subsidiaries that
have issued mandatorily redeemable non-controlling preferred interests. These
entities were determined to be VIEs in which we absorb the majority of the
variability, primarily due to the debt characteristics of the preferred
interest, which are classified as debt in accordance with SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity" in our Consolidated Condensed Balance Sheets. As a
result, we continue to consolidate these wholly owned subsidiaries.
Investments in Special Purpose Entities
Significant judgment was required in making an assessment of whether or not
a VIE was an SPE for purposes of adopting and applying FIN 46, as originally
issued at December 31, 2003. Since the current accounting literature does not
provide a definition of an SPE, our assessment was primarily based on the degree
to which the VIE aligned with the definition of a business outlined in FIN 46-R.
Entities that meet the definition of a business outlined in FIN 46-R and that
satisfy other formation and involvement criteria are not subject to the FIN 46-R
consolidation guidelines. The definitional characteristics of a business include
having: inputs such as long-lived assets; the ability to obtain access to
necessary materials and employees; processes such as strategic management,
operations and resource management; and the ability to obtain access to the
customers that purchase the outputs of the entity. Based on this assessment, we
determined that six VIE investments were in SPEs requiring further evaluation
and were subject to the application of FIN 46, as originally issued, as of
October 1, 2003: CNEM, PCF, PCF III and the Trusts.
On May 15, 2003, our wholly owned subsidiary, CNEM, completed the $82.8
million monetization of an existing power sales agreement with BPA. CNEM
borrowed $82.8 million secured by the spread between the BPA contract and
certain fixed power purchase contracts. CNEM was established as a
bankruptcy-remote entity and the $82.8 million loan is recourse only to CNEM's
assets and is not guaranteed by us. CNEM was determined to be a VIE in which we
were the Primary Beneficiary. Accordingly, the entity's assets and liabilities
were consolidated into our accounts as of June 30, 2003.
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On June 13, 2003, PCF, a wholly-owned stand-alone subsidiary of CES,
completed the offering of the PCF Notes, totaling $802.2 million. To facilitate
the transaction, we formed PCF as a wholly owned, bankruptcy remote entity with
assets and liabilities consisting of certain transferred power purchase and
sales contracts, which serve as collateral for the PCF Notes. The PCF Notes are
non-recourse to our other consolidated subsidiaries. PCF was originally
determined to be a VIE in which we were the Primary Beneficiary. Accordingly,
the entity's assets and liabilities were consolidated into our accounts as of
June 30, 2003.
As a result of the debt reserve monetization consummated on June 2, 2004,
we were required to evaluate our new investment in PCF III and to reevaluate our
investment in PCF under FIN 46-R (effective March 31, 2004). We determined that
the entities were VIEs but we were not the Primary Beneficiary and, therefore,
were required to deconsolidate the entities as of June 30, 2004.
Upon the application of FIN 46, as originally issued at December 31, 2003,
for our investments in SPEs, we determined that our equity investment in the
Trusts was not considered at-risk as defined in FIN 46 and that we did not have
a significant variable interest in the Trusts. Consequently, we deconsolidated
the Trusts as of December 31, 2003.
We created CNEM, PCF, PCF III and the Trusts to facilitate capital
transactions. However, in cases such as these where we have a continuing
involvement with the assets held by the deconsolidated SPE, we account for the
capital transaction with the SPE as a financing rather than a sale under EITF
Issue No. 88-18, "Sales of Future Revenue" ("EITF Issue No. 88-18") or Statement
of Financial Accounting Standard No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities -- a
Replacement of FASB Statement No. 125" ("SFAS No. 140"), as appropriate. When
EITF Issue No. 88-18 and SFAS No. 140 require us to account for a transaction as
a financing, derecognition of the assets underlying the financing is prohibited,
and the proceeds received from the transaction must be recorded as debt.
Accordingly, in situations where we account for transactions as financings under
EITF Issue No. 88-18 or SFAS No. 140, we continue to recognize the assets and
the debt of the deconsolidated SPE on our balance sheet. See Note 2 of the Notes
to Consolidated Financial Statements for a summary on how we account for our
SPEs when we have continuing involvement under EITF Issue No. 88-18 or SFAS No.
140.
Stock Based Compensation
Prior to 2003, we accounted for qualified stock compensation under APB
Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). Under APB
25, we were required to recognize stock compensation as expense only to the
extent that there is a difference in value between the market price of the stock
being offered to employees and the price those employees must pay to acquire the
stock. The expense measurement methodology provided by APB 25 is commonly
referred to as the "intrinsic value based method." To date, our stock
compensation program has been based primarily on stock options whose exercise
prices are equal to the market price of Calpine stock on the date of the stock
option grant; consequently, under APB 25 we had historically incurred minimal
stock compensation expense. On January 1, 2003, we prospectively adopted the
fair value method of accounting for stock-based employee compensation pursuant
to SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123") as
amended by SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition
and Disclosure" ("SFAS No. 148"). SFAS No. 148 amends SFAS No. 123 to provide
alternative methods of transition for companies that voluntarily change their
accounting for stock-based compensation from the less preferred intrinsic value
based method to the more preferred fair value based method. Prior to its
amendment, SFAS No. 123 required that companies enacting a voluntary change in
accounting principle from the intrinsic value methodology provided by APB 25
could only do so on a prospective basis; no adoption or transition provisions
were established to allow for a restatement of prior period financial
statements. SFAS No. 148 provides two additional transition options to report
the change in accounting principle -- the modified prospective method and the
retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure
requirements of SFAS No. 123 to require prominent disclosures in both annual and
interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results. We
elected to adopt the provisions of SFAS No. 123 on a prospective basis;
consequently, we are required to provide a pro-forma disclosure of net income
and earnings per share as if SFAS No. 123 accounting had been applied to all
prior periods presented within our financial statements. In December 2004 the
FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004)
("SFAS No. 123-R"), Share Based Payments. This Statement revises SFAS No. 123,
Accounting for Stock-Based Compensation and supersedes APB 25, Accounting for
Stock Issued to Employees, and its related implementation guidance. This
statement requires a public entity to measure the cost of employee services
received in exchange for an award of equity instruments based on the grant-date
fair value of the award (with limited exceptions), which must be recognized over
the period during which an employee is required to provide service in exchange
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for the award -- the requisite service period (usually the vesting period).
Adoption of SFAS No. 123-R is not expected to materially impact our operating
results, cash flows or financial position, due to the aforementioned discussion
surrounding our prior adoption of SFAS No. 123 as amended by SFAS No. 148.
Under SFAS No. 123, the fair value of a stock option or its equivalent is
estimated on the date of grant by using an option-pricing model, such as the
Black-Scholes model or a binomial model. The option-pricing model selected
should take into account, as of the stock option's grant date, the exercise
price and expected life of the stock option, the current price of the underlying
stock and its expected volatility, expected dividends on the stock, and the
risk-free interest rate for the expected term of the stock option.
The fair value calculated by this model is then recognized as compensation
expense over the period in which the related employee services are rendered.
Unless specifically defined within the provisions of the stock option granted,
the service period is presumed to begin on the grant date and end when the stock
option is fully vested. Depending on the vesting structure of the stock option
and other variables that are built into the option-pricing model, the fair value
of the stock option is recognized over the service period using either a
straight-line method (the single option approach) or a more conservative,
accelerated method (the multiple option approach). For consistency, we have
chosen the multiple option approach, which we have used historically for
pro-forma disclosure purposes. The multiple option approach views one four-year
option grant as four separate sub-grants, each representing 25% of the total
number of stock options granted. The first sub-grant vests over one year, the
second sub-grant vests over two years, the third sub-grant vests over three
years, and the fourth sub-grant vests over four years. Under this scenario, over
50% of the total fair value of the stock option grant is recognized during the
first year of the vesting period, and nearly 80% of the total fair value of the
stock option grant is recognized by the end of the second year of the vesting
period. By contrast, if we were to apply the single option approach, only 25%
and 50% of the total fair value of the stock option grant would be recognized as
compensation expense by the end of the first and second years of the vesting
period, respectively.
We have selected the Black-Scholes model, primarily because it has been the
most commonly recognized options-pricing model among U.S.-based corporations.
Nonetheless, we believe this model tends to overstate the true fair value of our
employee stock options in that our options cannot be freely traded, have vesting
requirements, and are subject to blackout periods during which, even if vested,
they cannot be traded. We will monitor valuation trends and techniques as more
companies adopt SFAS No. 123-R and as additional guidance is provided by FASB
and the SEC and review our choices as appropriate in the future. The key
assumption in our Black-Scholes model is the expected life of the stock option,
because it is this figure that drives our expected volatility calculation, as
well as our risk-free interest rate. The expected life of the option relies on
two factors -- the option's vesting period and the expected term that an
employee holds the option once it has vested. There is no single method
described by SFAS No. 123 for predicting future events such as how long an
employee holds on to an option or what the expected volatility of a company's
stock price will be; the facts and circumstances are unique to different
companies and depend on factors such as historical employee stock option
exercise patterns, significant changes in the market place that could create a
material impact on a company's stock price in the future, and changes in a
company's stock-based compensation structure.
We base our expected option terms on historical employee exercise patterns.
We have segregated our employees into four different categories based on the
fact that different groups of employees within our company have exhibited
different stock exercise patterns in the past, usually based on employee rank
and income levels. Therefore, we have concluded that we will perform separate
Black-Scholes calculations for four employee groups -- executive officers,
senior vice presidents, vice presidents, and all other employees.
We compute our expected stock price volatility based on our stock's
historical movements. For each employee group, we measure the volatility of our
stock over a period that equals the expected term of the option. In the case of
our executive officers, this means we measure our stock price volatility dating
back to our public inception in 1996, because these employees are expected to
hold their options for over 7 years after the options have fully vested. In the
case of other employees, volatility is only measured dating back 4 years. In the
short run, this causes other employees to generate a higher volatility figure
than the other company employee groups because our stock price has fluctuated
significantly in the past four years. As of December 31, 2004, the volatility
for our employee groups ranged from 69%-98%.
See Note 21 of the Notes to Consolidated Financial Statements for
additional information related to the January 1, 2003, adoption of SFAS Nos. 123
and 148 and the pro-forma impact that they would have had on our net income for
the years ended December 31, 2004, 2003 and 2002.
-54-
Initial Adoption of New Accounting Standards in 2004
See "Application of Critical Accounting Policies" above for our adoption of
FIN 46-R relating to variable interest entities and primary beneficiary.
EITF Issue No. 04-08 -- On September 30, 2004, the EITF reached a final
consensus on EITF Issue No. 04-08: "The Effect of Contingently Convertible Debt
on Diluted Earnings per Share" ("EITF Issue No. 04-08"). The guidance in EITF
Issue No. 04-08 is effective for periods ending after December 15, 2004, and
must be applied by retroactively restating previously reported earnings per
share results. The consensus requires companies that have issued contingently
convertible instruments with a market price trigger to include the effects of
the conversion in diluted earnings per share (if dilutive), regardless of
whether the price trigger had been met. Prior to this consensus, contingently
convertible instruments were not included in diluted earnings per share if the
price trigger had not been met. Typically, the affected instruments are
convertible into common stock of the issuer after the issuer's common stock
price has exceeded a predetermined threshold for a specified time period.
Calpine's $634 million of 2023 Convertible Senior Notes and $736 million
aggregate principal amount at maturity of 2014 Convertible Notes outstanding at
December 31, 2004, are affected by the new guidance. Depending on the closing
price of the Company's common stock at the end of each reporting period, the
conversion provisions in these Contingent Convertible Notes may significantly
impact the reported diluted earnings per share amounts in future periods.
For the twelve months ended December 31, 2004, approximately 8.6 million
weighted common shares potentially issuable under the Company's outstanding 2014
Convertible Notes were excluded from the diluted earnings per share calculations
as the inclusion of such shares would have been antidilutive because of the
Company's net loss. The 2023 Convertible Senior Notes would not have impacted
the diluted EPS calculation for any reporting period since issuance in November
2003, because the Company's closing stock price at each period end was below the
conversion price.
Summary of Dilution Potential of Our Contingent Convertible Notes: 2023
Convertible Senior Notes and 2014 Convertible Notes -- The table below assumes
normal conversion for the 2014 Convertible Notes and the 2023 Convertible Senior
Notes in which the principal amount is paid in cash, and the excess up to the
conversion value is paid in shares of Calpine common stock. The table shows only
the potential impact of our two contingent convertible notes issuances and does
not include the potential dilutive effect of HIGH TIDES III, the remaining 2006
Convertible Senior Notes or employee stock options. Additionally, we are still
assessing the potential impact of the SFAS No. 128-R exposure draft on our
convertible issues. See Note 2 of the Notes to Consolidated Financial Statements
for more information.
2014 2023
Convertible Convertible
Notes Senior Notes
------------ ------------
Size of issuance................................................................................ $736,000,000 $633,775,000
Conversion price per share...................................................................... $ 3.85 $ 6.50
Conversion rate................................................................................. 259.7403 153.8462
Trigger price (20% over conversion price)....................................................... $ 4.62 $ 7.80
Additional Shares
2014 2023
Convertible Convertible Share Share Dilution in
Future Calpine Common Stock Price Notes* Senior Notes Subtotal Increase EPS
- ------------------------------------------------------------------ ----------- ------------ ----------- -------- -----------
$5.00............................................................. 43,968,831 0 43,968,831 9.8% 8.9%
$7.50............................................................. 93,035,498 13,000,542 106,036,040 23.7% 19.2%
$10.00............................................................ 117,568,831 34,126,375 151,695,207 33.9% 25.3%
$20.00............................................................ 154,368,831 65,815,125 220,183,957 49.2% 33.0%
$40.00............................................................ 172,768,831 81,659,500 254,428,332 56.9% 36.2%
$100.00........................................................... 183,808,831 91,166,125 274,974,957 61.4% 38.1%
Basic earnings per share base at December 31, 2004................ 447,509,231
- ------------
<FN>
* In the case of the 2014 Convertible Notes, since the conversion value is
set for any given common stock price, more shares would be issued when the
accreted value is less than $1,000 than in the table above since the
accreted value (initially $839 per bond) is paid in cash, and the balance
of the conversion value is paid in shares. The incremental shares assuming
conversion when the accreted value is only $839 per bond are shown in the
table below:
</FN>
-55-
Incremental
Future Calpine Common Stock Price Shares
- --------------------------------------------------------------- -----------
$5.00.......................................................... 23,699,200
$7.50.......................................................... 15,799,467
$10.00......................................................... 11,849,600
$20.00......................................................... 5,924,800
$40.00......................................................... 2,962,400
$100.00........................................................ 1,184,960
-56-
EXHIBIT 99.3
Item 8. Financial Statements and Supplementary Data
Item 15. Exhibits, Financial Statement Schedules
(a)-1. Financial Statements and Other Information
Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheets December 31, 2004 and 2003
Consolidated Statements of Operations for the Years Ended
December 31, 2004, 2003, and 2002
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2004, 2003, and 2002
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2004, 2003, and 2002
Notes to Consolidated Financial Statements for the Years Ended
December 31, 2004, 2003, and 2002
-57-
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004
Page
Reports of Independent Registered Public Accounting Firms................................................................... 59
Consolidated Balance Sheets December 31, 2004 and 2003...................................................................... 62
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003, and 2002................................. 64
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2004, 2003, and 2002....................... 66
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003, and 2002................................. 67
Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003, and 2002............................ 69
-58-
Report of Independent Registered Public Accounting Firm
To the Board of Directors
And Stockholders of Calpine Corporation
We have audited the consolidated statements of operations, stockholders'
equity, and cash flows for the year ended December 31, 2002 of Calpine
Corporation and subsidiaries (the "Company"). These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, based on our audit, such consolidated financial statements
present fairly, in all material respects, the consolidated results of operations
and of cash flows for the year ended 2002 of Calpine Corporation and
subsidiaries, in conformity with accounting principles generally accepted in the
United States of America.
As discussed in Note 2 of the Notes to the Consolidated Financial
Statements, effective January 1, 2002, the Company adopted a new accounting
standard to account for the impairment of long-lived assets and discontinued
operations.
As discussed in Note 10 of the Notes to the Consolidated Financial
Statements, in June 2003, the Company approved the divestiture of its specialty
data center engineering business; in November 2003, the Company completed the
divestiture of certain oil and gas assets; in December 2003, the Company
committed to the divestiture of its fifty percent ownership interest in a power
project; in September 2004, the Company completed the divestiture of certain oil
and gas assets; in July 2005, the Company completed the divestiture of
substantially all of its remaining oil and gas exploration and production
properties and assets; in July 2005 the Company completed the divestiture of
Saltend Energy Centre.
/s/ Deloitte & Touche LLP
San Jose, California
March 10, 2003
(October 21, 2003 as to paragraph two of Note 10,
March 22, 2004 as to paragraphs six and twenty of Note 10,
March 31, 2005 as to paragraphs seven and eight of Note 10, and
October 14, 2005 as to paragraphs twelve and twenty-one of Note 10)
-59-
Report of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of Calpine Corporation:
We have completed an integrated audit of Calpine Corporation's 2004
consolidated financial statements and of its internal control over financial
reporting as of December 31, 2004 and an audit of its 2003 consolidated
financial statements in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Our opinions, based on our audits,
are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the accompanying consolidated balance sheets and related
consolidated statements of operations, stockholder's equity, and cash flows
present fairly, in all material respects, the financial position of Calpine
Corporation and its subsidiaries at December 31, 2004 and 2003, and the results
of their operations and their cash flows for each of the two years in the period
ended December 31, 2004 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the
financial statement schedule (not presented herein) for 2004 and 2003 listed in
the index appearing under Item 15(a)(2) of Calpine Corporation's 2004 Annual
Report on Form 10K presents fairly, in all material respects, the information
set forth therein when read in conjunction with the related consolidated
financial statements. These financial statements and financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits. We conducted our audits of these statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit of financial statements includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, the
Company changed the manner in which they calculate diluted earnings per share in
2004, changed the manner in which they account for asset retirement costs and
stock based compensation as of January 1, 2003, changed the manner in which they
account for certain financial instruments with characteristics of both
liabilities and equity effective July 1, 2003, changed the manner in which they
report gains and losses on certain derivative instruments not held for trading
purposes and account for certain derivative contracts with a price adjustment
feature effective October 1, 2003, adopted provisions of Financial Accounting
Standards Board Interpretation No. 46-R ("FIN-46R"), "Consolidation of Variable
Interest Entities -- an interpretation of ARB 51 (revised December 2003)," for
Special-Purpose-Entities as of December 31, 2003, and adopted FIN-46R for all
non-Special-Purpose-Entities on March 31, 2004.
Internal control over financial reporting
Also, we have audited management's assessment, included in Management's
Report on Internal Control over Financial Reporting (not presented herein)
appearing under Item 9A of Calpine Corporation's 2004 Annual Report on Form
10-K, that Calpine Corporation did not maintain effective internal control over
financial reporting as of December 31, 2004, because the Company did not
maintain effective controls over the accounting for income taxes and the
determination of current income taxes payable, deferred income tax assets and
liabilities and the related income tax provision (benefit) for continuing and
discontinued operations, based on criteria established in Internal Control --
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial reporting based
on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding of
internal control over financial reporting, evaluating management's assessment,
testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinions.
-60-
A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate. A material
weakness is a control deficiency, or combination of control deficiencies, that
results in more than a remote likelihood that a material misstatement of the
annual or interim financial statements will not be prevented or detected. The
following material weakness has been identified and included in management's
assessment. As of December 31, 2004, the Company did not maintain effective
controls over the accounting for income taxes and the determination of current
income taxes payable, deferred income tax assets and liabilities and the related
income tax provision (benefit) for continuing and discontinued operations.
Specifically, the Company did not have effective controls in place to (i)
identify and evaluate in a timely manner the tax implications of the
repatriation of funds from Canada (ii) appropriately determine the allocation of
the tax provision between continuing and discontinued operations (iii) ensure
there was adequate communication from the tax department to the accounting
department relating to the preparation of the tax provision (iv) ensure all
elements of the income tax provision were mathematically correct and (v) ensure
the rationale for certain tax positions was adequately documented. This control
deficiency resulted in the restatement of the Company's consolidated financial
statements for the three and nine months ended September 30, 2004 as well as
income tax related audit adjustments to the fourth quarter 2004 consolidated
financial statements. Additionally, this control deficiency could result in a
misstatement of current income taxes payable, deferred income tax assets and
liabilities and the related income tax provision (benefit) for continuing and
discontinued operations that would result in a material misstatement to annual
or interim financial statements that would not be prevented or detected.
Accordingly, management determined that this control deficiency constitutes a
material weakness. This material weakness was considered in determining the
nature, timing, and extent of audit tests applied in our audit of the 2004
consolidated financial statements, and our opinion regarding the effectiveness
of the Company's internal control over financial reporting does not affect our
opinion on those consolidated financial statements.
In our opinion, management's assessment that Calpine Corporation did not
maintain effective internal control over financial reporting as of December 31,
2004, is fairly stated, in all material respects, based on criteria established
in Internal Control -- Integrated Framework issued by the COSO. Also, in our
opinion, because of the effect of the material weakness described above on the
achievement of the objectives of the control criteria, Calpine Corporation has
not maintained effective internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal Control --
Integrated Framework issued by the COSO.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
March 31, 2005 (except for the effects of discontinued operations described in
Note 10, as to which the date is October 14, 2005)
-61-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2004 and 2003
2004 2003
-------------- --------------
(In thousands, except
share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents........................................................................ $ 718,023 $ 962,108
Accounts receivable, net of allowance of $7,317 and $7,283....................................... 1,048,010 948,092
Margin deposits and other prepaid expense........................................................ 438,125 374,290
Inventories...................................................................................... 174,307 133,201
Restricted cash.................................................................................. 593,304 383,788
Current derivative assets........................................................................ 324,206 494,912
Current assets held for sale..................................................................... 133,947 90,770
Other current assets............................................................................. 133,643 89,593
-------------- --------------
Total current assets............................................................................ 3,563,565 3,476,754
-------------- --------------
Restricted cash, net of current portion........................................................... 157,868 575,027
Notes receivable, net of current portion.......................................................... 203,680 213,629
Project development costs......................................................................... 150,179 139,953
Investments in power projects and oil and gas properties.......................................... 373,108 443,192
Deferred financing costs.......................................................................... 406,844 400,732
Prepaid lease, net of current portion............................................................. 424,586 414,058
Property, plant and equipment, net................................................................ 18,939,420 17,609,492
Goodwill.......................................................................................... 45,160 45,160
Other intangible assets, net...................................................................... 68,423 85,102
Long-term derivative assets....................................................................... 506,050 673,979
Long-term assets held for sale.................................................................... 1,718,724 2,618,371
Other assets...................................................................................... 658,481 608,483
-------------- --------------
Total assets.................................................................................... $ 27,216,088 $ 27,303,932
============== ==============
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable................................................................................. $ 983,008 $ 911,542
Accrued payroll and related expense.............................................................. 88,067 96,563
Accrued interest payable......................................................................... 385,794 321,176
Income taxes payable............................................................................. 57,234 18,026
Notes payable and borrowings under lines of credit, current portion.............................. 204,775 254,292
Preferred interests, current portion............................................................. 8,641 11,220
CCFC I financing, current portion................................................................ 3,208 3,208
Capital lease obligation, current portion........................................................ 5,490 4,008
Construction/project financing, current portion.................................................. 93,393 61,900
Senior notes and term loans, current portion..................................................... 718,449 14,500
Current derivative liabilities................................................................... 356,030 456,688
Current liabilities held for sale................................................................ 72,467 33,562
Other current liabilities........................................................................ 308,836 328,718
-------------- --------------
Total current liabilities....................................................................... 3,285,392 2,515,403
-------------- --------------
Notes payable and borrowings under lines of credit, net of current portion........................ 769,490 873,571
Notes payable to Calpine Capital Trusts........................................................... 517,500 1,153,500
Preferred interests, net of current portion....................................................... 497,896 232,412
Capital lease obligation, net of current portion.................................................. 283,429 193,741
CCFC I financing, net of current portion.......................................................... 783,542 785,781
CalGen/CCFC II financing.......................................................................... 2,395,332 2,200,358
Construction/project financing, net of current portion............................................ 1,905,658 1,209,506
Convertible Senior Notes Due 2006................................................................. 1,326 660,059
Convertible Senior Notes Due 2014................................................................. 620,197 --
Convertible Senior Notes Due 2023................................................................. 633,775 650,000
Senior notes, net of current portion.............................................................. 8,532,664 9,369,253
Deferred income taxes, net of current portion..................................................... 885,754 1,206,979
Deferred lease incentive.......................................................................... -- 50,228
Deferred revenue.................................................................................. 114,202 116,001
Long-term derivative liabilities.................................................................. 516,230 685,958
Long-term liabilities held for sale............................................................... 173,429 154,308
Other liabilities................................................................................. 319,154 214,729
-------------- --------------
Total liabilities............................................................................... 22,234,970 22,271,787
-------------- --------------
Commitments and contingencies (see Note 25)
Minority interests................................................................................ 393,445 410,892
-------------- --------------
-- Table Continues --
-62-
2004 2003
-------------- --------------
(In thousands, except
share and per share amounts)
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and
outstanding in 2004 and 2003.................................................................... -- --
Common stock, $.001 par value per share; authorized 2,000,000,000 shares in 2004; issued and
outstanding 536,509,231 shares in 2004 and 415,010,125 shares in 2003........................... 537 415
Additional paid-in capital....................................................................... 3,151,577 2,995,735
Additional paid-in capital, loaned shares........................................................ 258,100 --
Additional paid-in capital, returnable shares.................................................... (258,100) --
Retained earnings................................................................................ 1,326,048 1,568,509
Accumulated other comprehensive income........................................................... 109,511 56,594
-------------- --------------
Total stockholders' equity...................................................................... 4,587,673 4,621,253
-------------- --------------
Total liabilities and stockholders' equity...................................................... $ 27,216,088 $ 27,303,932
============== ==============
The accompanying notes are an integral part of these
consolidated financial statements.
-63-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended
December 31,
------------------------------------------------
2004 2003 2002
-------------- -------------- --------------
(In thousands, except per share amounts)
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue................................................. $ 5,297,820 $ 4,393,461 $ 3,031,731
Transmission sales revenue.................................................... 20,003 15,347 --
Sales of purchased power for hedging and optimization......................... 1,647,992 2,712,291 3,145,989
-------------- -------------- --------------
Total electric generation and marketing revenue.............................. 6,965,815 7,121,099 6,177,720
Oil and gas production and marketing revenue
Oil and gas sales............................................................. 4,146 2,399 27,455
Sales of purchased gas for hedging and optimization........................... 1,728,301 1,320,902 870,466
-------------- -------------- --------------
Total oil and gas production and marketing revenue........................... 1,732,447 1,323,301 897,921
Mark-to-market activities, net................................................. 13,404 (26,439) 21,485
Other revenue.................................................................. 69,189 106,237 10,683
-------------- -------------- --------------
Total revenue................................................................ 8,780,855 8,524,198 7,107,809
-------------- -------------- --------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense....................................................... 745,704 616,438 483,236
Royalty expense............................................................... 28,673 24,932 17,615
Transmission purchase expense................................................. 74,818 34,690 15,307
Purchased power expense for hedging and optimization.......................... 1,482,262 2,683,288 2,618,445
-------------- -------------- --------------
Total electric generation and marketing expense.............................. 2,331,457 3,359,348 3,134,603
Oil and gas operating and marketing expense
Oil and gas operating expense................................................. 8,582 19,992 26,525
Purchased gas expense for hedging and optimization........................... 1,716,714 1,279,568 821,065
-------------- -------------- --------------
Total oil and gas operating and marketing expense............................ 1,725,296 1,299,560 847,590
Fuel expense................................................................... 3,692,972 2,703,455 1,758,203
Depreciation, depletion and amortization expense............................... 463,748 400,107 300,011
Operating lease expense........................................................ 105,886 112,070 111,022
Other cost of revenue.......................................................... 90,742 42,296 7,276
-------------- -------------- --------------
Total cost of revenue........................................................ 8,410,101 7,916,836 6,158,705
-------------- -------------- --------------
Gross profit................................................................ 370,754 607,362 949,104
(Income) loss from unconsolidated investments in power projects................. 14,088 (75,724) (16,552)
Equipment cancellation and impairment cost...................................... 42,374 64,384 404,737
Long-term service agreement cancellation charge................................. 11,334 16,355 --
Project development expense..................................................... 24,409 21,803 66,981
Research and development expense................................................ 18,396 10,630 9,986
Sales, general and administrative expense....................................... 221,993 204,141 173,297
-------------- -------------- --------------
Income from operations.......................................................... 38,160 365,773 310,655
Interest expense................................................................ 1,116,800 716,124 417,368
Distributions on trust preferred securities..................................... -- 46,610 62,632
Interest (income)............................................................... (54,771) (39,202) (42,179)
Minority interest expense....................................................... 34,735 27,330 2,716
(Income) from repurchase of various issuances of debt........................... (246,949) (278,612) (118,020)
Other (income), net............................................................. (121,296) (45,989) (36,135)
-------------- -------------- --------------
Income (loss) before provision (benefit) for income taxes...................... (690,359) (60,488) 24,273
Provision (benefit) for income taxes............................................ (247,690) (34,387) 21,882
-------------- -------------- --------------
Income (loss) before discontinued operations and cumulative effect of a
change in accounting principle................................................ (442,669) (26,101) 2,391
Discontinued operations, net of tax provision of $21,236, $28,467 and $6,057.... 200,208 127,180 116,227
Cumulative effect of a change in accounting principle, net of tax provision
of $ --, $110,913, and $ --................................................... -- 180,943 --
-------------- -------------- --------------
Net income (loss)........................................................... $ (242,461) $ 282,022 $ 118,618
============== ============== ==============
Basic earnings per common share:
Weighted average shares of common stock outstanding............................ 430,775 390,772 354,822
Income (loss) before discontinued operations and cumulative effect of a
change in accounting principle................................................ $ (1.03) $ (0.07) $ 0.01
Discontinued operations, net of tax............................................ 0.47 0.33 0.32
Cumulative effect of a change in accounting principle, net of tax.............. -- 0.46 --
-------------- -------------- --------------
Net income (loss)........................................................... $ (0.56) $ 0.72 $ 0.33
============== ============== ==============
--Table Continues--
-64-
For the Years Ended
December 31,
------------------------------------------------
2004 2003 2002
-------------- -------------- --------------
(In thousands, except per share amounts)
Diluted earnings per common share:
Weighted average shares of common stock outstanding before dilutive effect
of certain convertible securities............................................. 430,775 396,219 362,533
Income (loss) before dilutive effect of certain convertible securities,
discontinued operations and cumulative effect of a change in
accounting principle.......................................................... $ (1.03) $ (0.07) $ 0.01
Dilutive effect of certain convertible securities(1)........................... -- -- --
-------------- -------------- --------------
Income (loss) before discontinued operations and cumulative effect of a
change in accounting principle................................................ (1.03) (0.07) 0.01
Discontinued operations, net of tax............................................ 0.47 0.33 0.32
Cumulative effect of a change in accounting principle, net of tax.............. -- 0.45 --
-------------- -------------- --------------
Net income(loss)............................................................ $ (0.56) $ 0.71 $ 0.33
============== ============== ==============
- ------------
<FN>
(1) See Note 24 of the Notes to Consolidated Financial Statements for further
information.
</FN>
The accompanying notes are an integral part of these
consolidated financial statements.
-65-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2004, 2003, and 2002
Accumulated
Other
Additional Comprehensive Total Comprehensive
Common Paid-In Retained Income Stockholders' Income
Stock Capital Earnings (Loss) Equity (Loss)
------ ---------- ---------- ------------- ------------- -------------
(In thousands, except share amounts)
Balance, January 1, 2002....................... $ 307 $2,040,833 $1,167,869 $ (240,880) $ 2,968,129
Issuance of 73,757,381 shares of common
stock, net of issuance costs................ 74 751,721 -- 751,795
Tax benefit from stock options exercised
and other................................... -- 9,949 - 9,949
Comprehensive income:
Net income................................... -- -- 118,618 -- 118,618 $ 118,618
Other comprehensive income................... 3,423 3,423 3,423
-------------
Total comprehensive income................... -- -- -- $ 122,041
------ ---------- ---------- ------------- ------------- =============
Balance, December 31, 2002..................... 381 2,802,503 1,286,487 (237,457) 3,851,914
====== ========== ========== === ========== =============
Issuance of 34,194,063 shares of common
stock, net of issuance costs................ 34 175,063 -- -- 175,097
Tax benefit from stock options exercised
and other................................... -- 2,097 -- -- 2,097
Stock compensation expense................... -- 16,072 -- -- 16,072
Comprehensive income:
Net income................................... -- -- 282,022 -- 282,022 $ 282,022
Other comprehensive income................... 294,051 294,051 294,051
-------------
Total comprehensive income................... -- -- -- -- -- $ 576,073
------ ---------- ---------- ------------- ------------- =============
Balance, December 31, 2003..................... $ 415 $2,995,735 $1,568,509 $ 56,594 $ 4,621,253
====== ========== ========== ============= =============
Issuance of 32,499,106 shares of common
stock, net of issuance costs................ 33 130,141 -- -- 130,174
Issuance of 89,000,000 shares of loaned
common stock................................ 89 258,100 -- -- 258,189
Returnable shares............................ (258,100) -- -- (258,100)
Tax benefit from stock options exercised
and other................................... -- 4,773 -- -- 4,773
Stock compensation expense................... 20,928 20,928
Comprehensive loss:
Net loss..................................... -- -- (242,461) (242,461) $ (242,461)
Other comprehensive income................... 52,917 52,917 52,917
-------------
Total comprehensive loss..................... -- -- -- -- -- $ (189,544)
------ ---------- ---------- ------------- ------------- =============
Balance, December 31, 2004..................... $ 537 $3,151,577 $1,326,048 $ 109,511 $ 4,587,673
====== ========== ========== ============= =============
The accompanying notes are an integral part of these
consolidated financial statements.
-66-
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
2004 2003 2002
------------- ------------- -------------
(In thousands)
Cash flows from operating activities:
Net income (loss)............................................................... $ (242,461) $ 282,022 $ 118,618
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization(1).................................... 833,375 732,410 538,777
Oil and gas impairment......................................................... 202,120 2,931 3,399
Equipment cancellation and asset impairment cost............................... 42,374 53,058 404,737
Development cost write off..................................................... -- 3,400 56,427
Deferred income taxes, net..................................................... (226,454) 150,323 23,206
Gain on sale of assets......................................................... (349,611) (65,351) (97,377)
Foreign currency transaction loss (gain)....................................... 25,122 33,346 (986)
Cumulative change in accounting principle...................................... -- (180,943) --
Income from repurchase of various issuances of debt............................ (246,949) (278,612) (118,020)
Minority interests............................................................. 34,735 27,330 2,716
Change in net derivative liability............................................. 14,743 59,490 (340,851)
(Income) loss from unconsolidated investments in power projects and oil
and gas properties............................................................ 9,717 (76,704) (16,490)
Distributions from unconsolidated investments in power projects and oil
and gas properties............................................................ 29,869 141,627 14,117
Stock compensation expense..................................................... 20,929 16,072 --
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable........................................................... (99,447) (221,243) 229,187
Other current assets.......................................................... (118,790) (160,672) 405,515
Other assets.................................................................. (95,699) (143,654) (305,908)
Accounts payable and accrued expense.......................................... 231,827 (111,901) (48,804)
Other liabilities............................................................. (55,505) 27,630 200,203
------------- ------------- -------------
Net cash provided by operating activities.................................... 9,895 290,559 1,068,466
------------- ------------- -------------
Cash flows from investing activities:
Purchases of property, plant and equipment...................................... (1,545,480) (1,886,013) (4,036,254)
Disposals of property, plant and equipment...................................... 1,066,481 206,804 400,349
Disposal of subsidiary.......................................................... 85,412 -- --
Acquisitions, net of cash acquired.............................................. (187,786) (6,818) --
Advances to joint ventures...................................................... (8,788) (54,024) (68,088)
Sale of collateral securities................................................... 93,963 -- --
Project development costs....................................................... (29,308) (35,778) (105,182)
Redemption of HIGH TIDES........................................................ (110,592) -- --
Cash flows from derivatives not designated as hedges............................ 16,499 42,342 26,091
(Increase) decrease in restricted cash.......................................... 210,762 (766,841) (73,848)
(Increase) decrease in notes receivable......................................... 10,235 (21,135) 8,926
Other........................................................................... (2,824) 6,098 10,179
------------- ------------- -------------
Net cash used in investing activities........................................ (401,426) (2,515,365) (3,837,827)
------------- ------------- -------------
Cash flows from financing activities:
Repurchase of Zero-Coupon Convertible Debentures Due 2021....................... -- -- (869,736)
Borrowings from notes payable and lines of credit............................... 101,781 1,672,871 1,348,798
Repayments of notes payable and lines of credit................................. (353,236) (1,769,072) (126,404)
Borrowings from project financing............................................... 3,743,930 1,548,601 725,111
Repayments of project financing................................................. (3,006,374) (1,638,519) (286,293)
Proceeds from issuance of Convertible Senior Notes.............................. 867,504 650,000 100,000
Repurchases of Convertible Senior Notes Due 2006................................ (834,765) (455,447) --
Repurchases of senior notes..................................................... (871,309) (1,139,812) --
Proceeds from issuance of senior notes.......................................... 878,814 3,892,040 --
Proceeds from preferred interests............................................... 360,000 -- --
Repayment of HIGH TIDES......................................................... (483,500) -- --
Proceeds from issuance of common stock.......................................... 98 15,951 751,795
Proceeds from income trust offerings............................................ -- 159,727 169,677
Financing costs................................................................. (204,139) (323,167) (42,783)
Other........................................................................... (31,752) 10,813 (12,769)
------------- ------------- -------------
Net cash provided by financing activities.................................... 167,052 2,623,986 1,757,396
------------- ------------- -------------
Effect of exchange rate changes on cash and cash equivalents..................... 16,101 13,140 (2,693)
Net increase (decrease) in cash and cash equivalents including
discontinued operations cash................................................... (208,378) 412,320 (1,014,658)
Change in discontinued operations cash classified as
current assets held for sale................................................... (35,707) (25,926) 12,248
------------- ------------- -------------
Net increase (decrease) in cash and cash equivalents............................. (244,085) 386,394 (1,002,410)
Cash and cash equivalents, beginning of period................................... 962,108 575,714 1,578,124
------------- ------------- -------------
Cash and cash equivalents, end of period......................................... $ 718,023 $ 962,108 $ 575,714
============= ============= =============
--Table Continues--
-67-
2004 2003 2002
------------- ------------- -------------
(In thousands)
Cash paid during the period for:
Interest, net of amounts capitalized............................................ $ 939,243 $ 462,714 $ 325,334
Income taxes.................................................................... $ 22,877 $ 18,415 $ 15,451
- ------------
<FN>
(1) Includes depreciation and amortization that is also recorded in sales,
general and administrative expense and interest expense.
Schedule of non cash investing and financing activities:
o 2004 issuance of 24.3 million shares of common stock in exchange for
$40.0 million par value of HIGH TIDES I and $75.0 million par value of
HIGH TIDES II
o 2004 capital lease entered into for the King City facility for an
initial asset balance of $114.9 million
o 2004 issuance of 89 million shares of Calpine common stock pursuant to
a Share Lending Agreement. See Note 17 for more information regarding
the 89 million shares issued
o 2004 acquired the remaining 50% interest in the Aries Power Plant for
$3.7 million cash and $220.0 million of assumed liabilities, including
debt of $173.2 million
o 2003 issuance of 30 million shares of common stock in exchange for
$182.5 million of debt, convertible debt and preferred securities
o 2002 non-cash consideration of $88.4 million in tendered Company debt
received upon the sale of its British Columbia oil and gas properties
</FN>
The accompanying notes are an integral part of these consolidated financial
statements.
-68-
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2004, 2003, and 2002
1. Organization and Operations of the Company
Calpine Corporation, a Delaware corporation, and subsidiaries
(collectively, "Calpine" or the "Company") are engaged in the generation of
electricity in the United States of America and Canada and were engaged in the
generation of electricity in the United Kingdom until the sale of the Saltend
Energy Centre in July 2005. See Note 10 for a discussion of the subsequent sale
of the Saltend Energy Centre. The Company is involved in the development,
construction, ownership and operation of power generation facilities and the
sale of electricity and its by-product, thermal energy, primarily in the form of
steam. The Company has ownership interests in, and operates, gas-fired power
generation and cogeneration facilities and gas pipelines, geothermal steam
fields and geothermal power generation facilities in the United States of
America. Until we sold our remaining oil and gas assets in July 2005, we also
had ownership interests in gas fields and gathering systems in the United
States. In Canada, the Company has ownership interests in, and operates,
gas-fired power generation facilities. In Mexico, Calpine is a joint venture
participant in a gas-fired power generation facility under construction. The
Company markets electricity produced by its generating facilities to utilities
and other third party purchasers. Thermal energy produced by the gas-fired power
cogeneration facilities is primarily sold to industrial users. The Company
offers to third parties energy procurement, liquidation and risk management
services, combustion turbine component parts and repair and maintenance services
world-wide. The Company also provides engineering, procurement, construction
management, commissioning and operations and maintenance ("O&M") services.
2. Summary of Significant Accounting Policies
Principles of Consolidation -- The accompanying consolidated financial
statements include accounts of the Company and its wholly owned and
majority-owned subsidiaries. The Company adopted Financial Accounting Standards
Board ("FASB") Interpretation No. ("FIN") 46, "Consolidation of Variable
Interest Entities, an interpretation of ARB 51" ("FIN 46") for its investments
in special purpose entities as of December 31, 2003. These consolidated
financial statements as of December 31, 2004 and 2003, and for the twelve months
ended December 31, 2004, also include the accounts of those special purpose
Variable Interest Entities ("VIE") for which the Company is the Primary
Beneficiary. The Company adopted FIN 46, as revised ("FIN 46-R") for its
investments in non-special purpose VIEs on March 31, 2004. These consolidated
financial statements as of December 31, 2004 and for the nine months ended
December 31, 2004 include the accounts of non-special purpose VIEs for which the
Company is the Primary Beneficiary. Certain less-than-majority-owned
subsidiaries are accounted for using the equity method or cost method. For
equity method investments, the Company's share of income is calculated according
to the Company's equity ownership or according to the terms of the appropriate
partnership agreement (see Note 7). For cost method investments, income is
recognized when equity distributions are received. All intercompany accounts and
transactions are eliminated in consolidation.
Unrestricted Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the indentures and credit agreement governing
the various tranches of the Company's second-priority secured indebtedness
(collectively, the "Second Priority Secured Debt Instruments"). The Company has
designated certain of its subsidiaries as "unrestricted subsidiaries" under the
Second Priority Secured Debt Instruments. A subsidiary with "unrestricted"
status thereunder generally is not required to comply with the covenants
contained therein that are applicable to "restricted subsidiaries." The Company
has designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy
Cogen, L.P. as "unrestricted subsidiaries" for purposes of the Second Priority
Secured Debt Instruments.
Reclassifications -- Certain prior years' amounts in the consolidated
financial statements have been reclassified to conform to the 2004 presentation.
These include a reclassification between sales, general and administrative
expense ("SG&A") and plant operating expense for information technology and
stock compensation costs and reclassifications to begin separately disclosing:
(1) research and development expense (formerly in SG&A), (2) transmission sales
revenue (formerly in electricity and steam revenue), and (3) transmission
purchase expense (formerly in plant operating expense).
Certain prior year amounts have also been reclassified to conform with
discontinued operations presentation including the reclassification of the oil
and gas impairments which were formerly in depreciation, depletion and
amortization expense. See Note 10 for information on the Company's discontinued
operations.
-69-
Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expense during the reporting
period. Actual results could differ from those estimates. The most significant
estimates with regard to these financial statements relate to useful lives and
carrying values of assets (including the carrying value of projects in
development, construction, and operation), provision for income taxes, fair
value calculations of derivative instruments and associated reserves,
capitalization of interest, primary beneficiary determination for the Company's
investments in VIEs, the outcome of pending litigation, and prior to the
divestiture of our remaining oil and gas assets (see Note 10 for more
information regarding this sale), estimates of oil and gas reserve quantities
used to calculate depletion, depreciation and impairment of oil and gas property
and equipment.
Foreign Currency Translation -- Through its international operations, the
Company owns subsidiary entities in several countries. These entities generally
have functional currencies other than the U.S. dollar; in most cases, the
functional currency is consistent with the local currency of the host country
where the particular entity is located. In accordance with FASB Statement of
Financial Accounting Standards ("SFAS") No. 52, "Foreign Currency Translation,"
("SFAS No. 52") the Company translates the financial statements of its foreign
subsidiaries from their respective functional currencies into the U.S. dollar,
which represents the Company's reporting currency.
Assets and liabilities held by the foreign subsidiaries are translated into
U.S. dollars using exchange rates in effect at the balance sheet date. Certain
long-term assets (such as the investment in a subsidiary company) as well as
equity accounts are translated into U.S. dollars using historical exchange rates
at the date the specific transaction occurred which created the asset or equity
balance (such as the date of the initial investment in the subsidiary). Income
and expense accounts are translated into U.S. dollars using average exchange
rates during the reporting period. All translation gains and losses that result
from translating the financial statements of the Company's foreign subsidiaries
from their respective functional currencies into the U.S. dollar reporting
currency are recognized within the Cumulative Translation Adjustment ("CTA")
account, which is a component of Other Comprehensive Income ("OCI") within
Stockholders' Equity.
In certain cases, the Company and its foreign subsidiary entities hold
monetary assets and/or liabilities that are not denominated in the functional
currencies referred to above. In such instances, the Company applies the
provisions of SFAS No. 52 to account for the monthly re-measurement gains and
losses of these assets and liabilities into the functional currencies for each
entity.
For foreign currency transactions designated as economic hedges of a net
investment in a foreign entity and for intercompany foreign currency
transactions which are of a long-term investment nature, the Company records the
re-measurement gains and losses through the CTA account, in accordance with
Paragraph 20 of SFAS No. 52.
All other foreign currency transactions that do not qualify for the
Paragraph 20 exclusion are re-measured at the end of each month into the proper
functional currency, and the gains and losses resulting from such re-
measurement are recorded within net income, in accordance with Paragraph 15 of
SFAS No. 52.
For the years ended December 31, 2004, 2003 and 2002, the Company
recognized foreign currency transaction losses from continuing operations of
$41.6 million, $34.5 million and $1.0 million, respectively, which were recorded
within Other Income on the Company's Consolidated Statements of Operations.
Additionally, the Company settled a series of forward foreign exchange contracts
associated with the sale of its Canadian oil and gas assets in 2004. See Note 10
for further discussion or the settlement of these contracts within discontinued
operations. Subsequent to December 31, 2004, the Company was exposed to
significant exchange rate movements between the Canadian dollar and the U.S.
dollar due to several large intercompany transactions between Calpine's U.S. and
Canadian subsidiaries. Subsequent to December 31, 2004, the U.S. dollar
strengthened considerably against the Canadian dollar and the Company recognized
re-measurement gains on these transactions; however, these gains could reverse
based on future exchange rate movements.
Fair Value of Financial Instruments -- The carrying value of accounts
receivable, marketable securities, accounts payable and other payables
approximate their respective fair values due to their short maturities. See Note
18 for disclosures regarding the fair value of the senior notes.
Cash and Cash Equivalents -- The Company considers all highly liquid
investments with an original maturity of three months or less to be cash
equivalents. The carrying amount of these instruments approximates fair value
because of their short maturity.
-70-
The Company has certain project debt and lease agreements that establish
working capital accounts which limit the use of certain cash balances to the
operations of the respective plants. At December 31, 2004 and 2003, $284.4
million and $392.3 million, respectively, of the cash and cash equivalents
balance was subject to such project debt and lease agreements.
Accounts Receivable and Accounts Payable -- Accounts receivable and payable
represent amounts due from customers and owed to vendors. Accounts receivable
are recorded at invoiced amounts, net of reserves and allowances and do not bear
interest. Reserve and allowance accounts represent the Company's best estimate
of the amount of probable credit losses in the Company's existing accounts
receivable. The Company reviews the financial condition of customers prior to
granting credit. The Company determines the allowance based on a variety of
factors, including the length of time receivables are past due, economic trends
and conditions affecting its customer base, significant one-time events and
historical write off experience. Also, specific provisions are recorded for
individual receivables when the Company becomes aware of a customer's inability
to meet its financial obligations, such as in the case of bankruptcy filings or
deterioration in the customer's operating results or financial position. The
Company reviews the adequacy of its reserves and allowances quarterly.
Generally, past due balances over 90 days and over a specified amount are
individually reviewed for collectibility. Account balances are charged off
against the allowance after all means of collection have been exhausted and the
potential for recovery is considered remote.
The accounts receivable and payable balances also include settled but
unpaid amounts relating to hedging, balancing, optimization and trading
activities of Calpine Energy Services, L.P. ("CES"). Some of these receivables
and payables with individual counterparties are subject to master netting
agreements whereby the Company legally has a right of offset and the Company
settles the balances net. However, for balance sheet presentation purposes and
to be consistent with the way the Company presents the majority of amounts
related to hedging, balancing and optimization activities in its consolidated
statements of operations under Staff Accounting Bulletin ("SAB") No. 101
"Revenue Recognition in Financial Statements," as amended by SAB No. 104
"Revenue Recognition" (collectively "SAB No. 101"), and Emerging Issues Task
Force ("EITF") Issue No. 99-19 "Reporting Revenue Gross as a Principal Versus
Net as an Agent," ("EITF Issue No. 99-19") the Company presents its receivables
and payables on a gross basis. CES receivable balances (which comprise the
majority of the accounts receivable balance at December 31, 2004) greater than
30 days past due are individually reviewed for collectibility, and if deemed
uncollectible, are charged off against the allowance accounts or reversed out of
revenue after all means of collection have been exhausted and the potential for
recovery is considered remote. The Company does not have any off-balance-sheet
credit exposure related to its customers.
Inventories -- The Company's inventories primarily include spare parts,
stored gas and oil as well as work-in-process. Inventories are valued at the
lower of cost or market. The cost for spare parts as well as stored gas and oil
is generally determined using the weighted average cost method. Work-in-process
is generally determined using the specific identification method and represents
the value of manufactured goods during the manufacturing process. The inventory
balance at December 31, 2004, was $174.3 million. This balance is comprised of
$112.0 million of spare parts, $53.2 million of stored gas and oil as well as
$9.1 million of work-in-process. The inventory balance at December 31, 2003, was
$133.2 million. This balance is comprised of $83.8 million of spare parts, $43.5
million of stored gas and oil as well as $5.9 million of work-in-process.
Margin Deposits -- As of December 31, 2004 and 2003, as credit support for
the gas and power procurement and risk management activities conducted on the
Company's behalf, CES had deposited net amounts of $248.9 million and $188.0
million, respectively, in cash as margin deposits.
Available-for-Sale Debt Securities -- See Note 3 for a discussion of the
Company's accounting policy for its available-for-sale debt securities.
Property, Plant and Equipment, Net -- See Note 4 for a discussion of the
Company's accounting policies for its property, plant and equipment.
Project Development Costs -- The Company capitalizes project development
costs once it is determined that it is highly probable that such costs will be
realized through the ultimate construction of a power plant. These costs include
professional services, salaries, permits, capitalized interest, and other costs
directly related to the development of a new project. Upon commencement of
construction, these costs are transferred to construction in progress ("CIP"), a
component of property, plant and equipment. Upon the start-up of plant
operations, these construction costs are reclassified as buildings, machinery
and equipment, also a component of property, plant and equipment, and are
depreciated as a component of the total cost of the plant over its estimated
useful life. Capitalized project costs are charged to expense if the Company
determines that the project is no longer probable or to the extent it is
impaired. Outside services and other third party costs are capitalized for
acquisition projects.
-71-
Investments in Power Projects and Oil and Gas Properties -- See Note 7 for
a discussion of the Company's accounting policies for its investments in power
projects and oil and gas properties. In November 2004 one of the Company's
equity method investees filed for protection under Chapter 11 of the U.S.
Bankruptcy code. As a result of this legal proceeding, the Company has lost
significant influence and control of the project. Consequently, as of December
31, 2004, the Company no longer accounts for this investment using the equity
method but instead uses the cost method. See Note 7 for a discussion of this
event.
Restricted Cash -- The Company is required to maintain cash balances that
are restricted by provisions of its debt agreements, lease agreements and
regulatory agencies. These amounts are held by depository banks in order to
comply with the contractual provisions requiring reserves for payments such as
for debt service, rent service, major maintenance and debt repurchases. Funds
that can be used to satisfy obligations due during the next twelve months are
classified as current restricted cash, with the remainder classified as
non-current restricted cash. Restricted cash is generally invested in accounts
earning market rates; therefore the carrying value approximates fair value. Such
cash is excluded from cash and cash equivalents in the consolidated statements
of cash flows.
As part of a prior business acquisition which included certain facilities
subject to a pre-existing operating lease, the Company acquired certain
restricted cash balances comprised of a portfolio of debt securities. This
portfolio is classified as held-to-maturity because the Company has the intent
and ability to hold the securities to maturity. The securities are held in
escrow accounts to support operating activities of the leased facilities and
consist of a $17.0 million debt security maturing in 2015 and a $7.4 million
debt security maturing in 2023. This portfolio is stated at amortized cost,
adjusted for amortization of premiums and accretion discounts to maturity.
Of the Company's restricted cash at December 31, 2004, $276.0 million
relates to the assets of the following entities, each an entity with its
existence separate from the Company and other subsidiaries of the Company.
Bankruptcy-Remote Subsidiary 2004
- --------------------------------------------------------------------- --------
Power Contracting Finance, LLC....................................... $ 175.6
Gilroy Energy Center, LLC............................................ 53.5
Rocky Mountain Energy Center, LLC.................................... 18.1
Riverside Energy Center, LLC......................................... 7.1
Calpine Energy Management, L.P....................................... 6.9
Calpine King City Cogen, LLC......................................... 6.7
Calpine Northbrook Energy Marketing, LLC............................. 6.0
Power Contracting Finance III, LLC................................... 1.5
Creed Energy Center, LLC............................................. 0.3
Goose Haven Energy Center, LLC....................................... 0.3
Notes Receivable -- See Note 8 for a discussion of the Company's accounting
policies for its notes receivable.
Preferred Interests -- As outlined in SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity,"
("SFAS No. 150") the Company classifies preferred interests that embody
obligations to transfer cash to the preferred interest holder, in short-term and
long-term debt. These instruments require the Company to make priority
distributions of available cash, as defined in each preferred interest
agreement, representing a return of the preferred interest holder's investment
over a fixed period of time and at a specified rate of return in priority to
certain other distributions to equity holders. The return on investment is
recorded as interest expense under the interest method over the term of the
priority period. See Note 12 for a further discussion of the Company's
accounting policies for its preferred interests.
Deferred Financing Costs -- See Note 11 for a discussion of the Company's
accounting policies for deferred financing costs.
Goodwill and Other Intangible Assets -- See Note 5 for a discussion of the
Company's accounting for goodwill and other intangible assets.
Long-Lived Assets -- In accordance with SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," ("SFAS No. 144") the Company
evaluates the impairment of long-lived assets, including construction and
development projects, based on the projection of undiscounted pre-interest
expense and pre-tax expense cash flows whenever events or changes in
circumstances indicate that the carrying amounts of such assets may not be
recoverable. The significant assumptions that the Company uses in its
undiscounted future cash flow estimates include the future supply and demand
relationships for electricity and natural gas, the expected pricing for those
commodities and the resultant spark spreads in the various regions where the
Company generates, and prior to the divestiture of our remaining oil and gas
assets (see Note 10 for more information), external oil and gas year-end reserve
-72-
reports prepared by licensed independent petroleum engineering firms. In the
event such cash flows are not expected to be sufficient to recover the recorded
value of the assets, the assets are written down to their estimated fair values.
See Note 4 for more information on the impairment charges recorded for oil and
gas properties. Certain of the Company's generating assets are located in
regions with depressed demands and market spark spreads. The Company's forecasts
assume that spark spreads will increase in future years in these regions as the
supply and demand relationships improve.
Concentrations of Credit Risk -- Financial instruments which potentially
subject the Company to concentrations of credit risk consist primarily of cash,
accounts receivable, notes receivable, and commodity contracts. The Company's
cash accounts are generally held in FDIC insured banks. The Company's accounts
and notes receivable are concentrated within entities engaged in the energy
industry, mainly within the United States (see Notes 8 and 22). The Company
generally does not require collateral for accounts receivable from end-user
customers, but evaluates the net accounts receivable, accounts payable, and fair
value of commodity contracts with trading companies and may require security
deposits or letters of credit to be posted if exposure reaches a certain level.
Deferred Revenue -- The Company's deferred revenue consists primarily of
deferred gains related to certain sale/leaseback transactions as well as
deferred revenue for long-term power supply contracts including contracts
accounted for as operating leases.
Trust Preferred Securities -- Prior to the adoption of FIN 46, as
originally issued, for special purpose VIEs on October 1, 2003, the Company's
trust preferred securities were accounted for as a minority interest in the
balance sheet and reflected as "Company-obligated mandatorily redeemable
convertible preferred securities of subsidiary trusts." The distributions were
reflected in the Consolidated Statements of Operations as "distributions on
trust preferred securities" through September 30, 2003. Financing costs related
to these issuances are netted with the principal amounts and were accreted as
minority interest expense over the securities' 30-year maturity using the
straight-line method which approximated the effective interest rate method. Upon
the adoption of FIN 46, the Company deconsolidated the Calpine Capital Trusts.
Consequently, the Trust Preferred Securities are no longer on the Company's
Consolidated Balance Sheet and were replaced with the debentures issued by the
Company to the Calpine Capital Trusts. Due to the relationship with the Calpine
Capital Trusts, the Company considers Calpine Capital Trust ("Trust I"), Calpine
Capital Trust II ("Trust II") and Calpine Capital Trust III ("Trust III") to be
related parties. The interest payments on the debentures are now reflected in
the Consolidated Statements of Operations as "interest expense." See Note 12 for
further information.
Revenue Recognition -- The Company is primarily an electric generation
company with consolidated revenues being earned from operating a portfolio of
mostly wholly owned plants. Equity investment income is also earned from plants
in which our ownership interest is 50% or less or the Company is not the Primary
Beneficiary under FIN 46-R, and which are accounted for under the equity method.
In conjunction with its electric generation business, the Company also produces,
as a by-product, thermal energy for sale to customers, principally steam hosts
at the Company's cogeneration sites. In addition, prior to the sale of its
remaining oil and gas assets in July 2005 (see Note 10 for further information),
the Company acquired and produced natural gas for its own consumption and sold
oil produced to third parties.
Where applicable, revenues are recognized under EITF Issue No. 91-06,
"Revenue Recognition of Long Term Power Sales Contracts," ("EITF Issue No.
91-06") ratably over the terms of the related contracts. To protect and enhance
the profit potential of its electric generation plants, the Company, through its
subsidiary, CES, enters into electric and gas hedging, balancing, and
optimization transactions, subject to market conditions, and CES has also, from
time to time, entered into contracts considered energy trading contracts under
EITF Issue No. 02-03, "Issues Related to Accounting for Contracts Involved in
Energy Trading and Risk Management" ("EITF Issue No. 02-03"). CES executes these
transactions primarily through the use of physical forward commodity purchases
and sales and financial commodity swaps and options. With respect to its
physical forward contracts, CES generally acts as a principal, takes title to
the commodities, and assumes the risks and rewards of ownership. Therefore, when
CES does not hold these contracts for trading purposes and, in accordance with
SAB No. 101, and EITF Issue No. 99-19, the Company records settlement of the
majority of its non-trading physical forward contracts on a gross basis.
The Company, through its wholly owned subsidiary, Power Systems MFG., LLC
("PSM"), designs and manufactures certain spare parts for gas turbines. The
Company in the past has also generated revenue by occasionally loaning funds to
power projects, and currently provides O&M services to third parties and to
certain unconsolidated power projects. The Company also sells engineering and
construction services to third parties for power projects. Further details of
the Company's revenue recognition policy for each type of revenue transaction
are provided below:
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Accounting for Commodity Contracts
Commodity contracts are evaluated to determine whether the contract is (1)
accounted for as a lease (2) accounted for as a derivative (3) or accounted for
as an executory contract and additionally whether the financial statement
presentation is gross or net.
Leases -- Commodity contracts are evaluated for lease accounting in
accordance with SFAS No. 13, "Accounting for Leases," ("SFAS No. 13") and EITF
Issue No. 01-08, "Determining Whether an Arrangement Contains a Lease," (EITF
Issue No. 01-08). EITF Issue No. 01-08 clarifies the requirements of identifying
whether an arrangement should be accounted for as a lease at its inception. The
guidance in the consensus is designed to broaden the scope of arrangements, such
as power purchase agreements ("PPA"), accounted for as leases. EITF Issue No.
01-08 requires both parties to an arrangement to determine whether a service
contract or similar arrangement is, or includes, a lease within the scope of
SFAS No. 13. The consensus is being applied prospectively to arrangements agreed
to, modified, or acquired in business combinations on or after July 1, 2003.
Prior to adopting EITF Issue No. 01-08, the Company had accounted for certain
contractual arrangements as leases under existing industry practices, and the
adoption of EITF Issue No. 01-08 did not materially change the Company's
accounting for leases. Under the guidance of SFAS No. 13, operating leases with
minimum lease rentals which vary over time must be levelized over the term of
the contract. The Company currently levelizes these contracts on a straight-line
basis. See Note 22 for additional information on our operating leases. For
income statement presentation purposes, income from PPAs accounted for as leases
is classified within electricity and steam revenue in the Company's consolidated
statements of operations.
Derivative Instruments -- SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS No. 133") as amended and interpreted
by other related accounting literature, establishes accounting and reporting
standards for derivative instruments (including certain derivative instruments
embedded in other contracts). SFAS No. 133 requires companies to record
derivatives on their balance sheets as either assets or liabilities measured at
their fair value unless exempted from derivative treatment as a normal purchase
and sale. All changes in the fair value of derivatives are recognized currently
in earnings unless specific hedge criteria are met, which requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting.
Accounting for derivatives at fair value requires the Company to make
estimates about future prices during periods for which price quotes are not
available from sources external to the Company. As a result, the Company is
required to rely on internally developed price estimates when external price
quotes are unavailable. The Company derives its future price estimates, during
periods where external price quotes are unavailable, based on an extrapolation
of prices from periods where external price quotes are available. The Company
performs this extrapolation using liquid and observable market prices and
extending those prices to an internally generated long-term price forecast based
on a generalized equilibrium model.
SFAS No. 133 sets forth the accounting requirements for cash flow and fair
value hedges. SFAS No. 133 provides that the effective portion of the gain or
loss on a derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of OCI and be reclassified into earnings
in the same period during which the hedged forecasted transaction affects
earnings. The remaining gain or loss on the derivative instrument, if any, must
be recognized currently in earnings. SFAS No. 133 provides that the changes in
fair value of derivatives designated as fair value hedges and the corresponding
changes in the fair value of the hedged risk attributable to a recognized asset,
liability, or unrecognized firm commitment be recorded in earnings. If the fair
value hedge is effective, the amounts recorded will offset in earnings.
With respect to cash flow hedges, if the forecasted transaction is no
longer probable of occurring, the associated gain or loss recorded in OCI is
recognized currently. In the case of fair value hedges, if the underlying asset,
liability or firm commitment being hedged is disposed of or otherwise
terminated, the gain or loss associated with the underlying hedged item is
recognized currently. If the hedging instrument is terminated prior to the
occurrence of the hedged forecasted transaction for cash flow hedges, or prior
to the settlement of the hedged asset, liability or firm commitment for fair
value hedges, the gain or loss associated with the hedge instrument remains
deferred.
Where the Company's derivative instruments are subject to the special
transition adjustment for the estimated future economic benefits of these
contracts upon adoption of Derivatives Implementation Group ("DIG") Issue No.
C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely
Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature,"
("DIG Issue No. C20") the Company will amortize the corresponding asset recorded
upon adoption of DIG Issue No. C20 through a charge to earnings in future
periods. Accordingly on October 1, 2003, the date the Company adopted DIG Issue
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No. C20, the Company recorded other current assets and other assets of
approximately $33.5 million and $259.9 million, respectively, and a cumulative
effect of a change in accounting principle of approximately $181.9 million, net
of $111.5 million of tax. For all periods subsequent to October 1, 2003, the
Company will account for the contracts as normal purchases and sales under the
provisions of DIG Issue No. C20.
Mark-to-Market, net activity includes realized settlements of and
unrealized mark-to-market gains and losses on both power and gas derivative
instruments not designated as cash flow hedges, including those held for trading
purposes. Gains and losses due to ineffectiveness on hedging instruments are
also included in unrealized mark-to-market gains and losses. Trading activity is
presented net in accordance with EITF Issue No. 02-03.
Executory Contracts -- Where commodity contracts do not qualify as leases
or derivatives, the contracts are classified as executory contracts. These
contracts apply traditional accrual accounting unless the revenue must be
levelized per EITF Issue No. 91-06. The Company currently accounts for one
commodity contract under EITF Issue No. 91-06 which is levelized over the term
of the agreement.
Financial Statement Presentation -- Where the Company's derivative
instruments are subject to a netting agreement and the criteria of FIN 39
"Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB
Opinion No. 10 and SFAS No. 105)" ("FIN 39") are met, the Company presents its
derivative assets and liabilities on a net basis in its balance sheet. The
Company has chosen this method of presentation because it is consistent with the
way related mark-to-market gains and losses on derivatives are recorded in its
Consolidated Statements of Operations and within OCI.
Presentation of revenue under EITF Issue No. 03-11 "Reporting Realized
Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133 and
Not `Held for Trading Purposes' As Defined in EITF Issue No. 02-03: "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" ("EITF
Issue No. 03-11") -- The Company accounts for certain of its power sales and
purchases on a net basis under EITF Issue No. 03-11, which the Company adopted
on a prospective basis on October 1, 2003. Transactions with either of the
following characteristics are presented net in the Company's Consolidated
Financial Statements: (1) transactions executed in a back-to-back buy and sale
pair, primarily because of market protocols; and (2) physical power purchase and
sale transactions where the Company's power schedulers net the physical flow of
the power purchase against the physical flow of the power sale (or "book out"
the physical power flows) as a matter of scheduling convenience to eliminate the
need to schedule actual power delivery. These book out transactions may occur
with the same counterparty or between different counterparties where the Company
has equal but offsetting physical purchase and delivery commitments. In
accordance with EITF Issue No. 03-11, the Company netted the following amounts
(in thousands):
Year Ended December 31,
-----------------------
2004 2003
---------- ----------
Sales of purchased power for hedging and optimization.. $1,676,003 $ 256,573
---------- ----------
Purchased power expense for hedging and optimization... $1,676,003 $ 256,573
---------- ----------
Electric Generation and Marketing Revenue -- This includes electricity and
steam sales, transmission sales revenue and sales of purchased power for
hedging, balancing and optimization. Subject to market and other conditions, the
Company manages the revenue stream for its portfolio of electric generating
facilities. The Company markets on a system basis both power generated by its
plants in excess of amounts under direct contract between the plant and a third
party, and power purchased from third parties, through hedging, balancing and
optimization transactions. The Company also, from time-to-time, sells excess
transmission capacity. CES performs a market-based allocation of electric
generation and marketing revenue to electricity and steam sales (based on
electricity delivered by the Company's electric generating facilities) and to
sales of purchased power.
Oil and Gas Production and Marketing Revenue -- This includes sales to
third parties of oil, gas and related products that were produced by the
Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and,
subject to market and other conditions, sales of purchased gas arising from
hedging, balancing and optimization transactions. Oil and gas sales for produced
products were recognized pursuant to the sales method, net of royalties. If the
Company had recorded gas sales on a particular well or field in excess of its
share of remaining estimated reserves, then the excessive gas sale imbalance is
recognized as a liability. If the Company was under-produced on a particular
well or field, and it was determined that an over-produced partner's share of
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remaining reserves was insufficient to settle the gas imbalance, the Company
would recognize a receivable, to the extent collectible, from the over-produced
partner. See Note 10 for a discussion of the subsequent sale of the Company's
remaining oil and gas assets in July 2005.
Other Revenue -- This includes O&M contract revenue, PSM and Thomassen
Turbine Systems B.V. ("TTS") revenue from sales to third parties, engineering
and construction revenue and miscellaneous revenue.
Plant Operating Expense -- This primarily includes employee expenses,
repairs and maintenance, insurance, and property taxes.
Purchased Power and Purchased Gas Expense -- The cost of power purchased
from third parties for hedging, balancing and optimization activities is
recorded as purchased power expense, a component of electric generation and
marketing expense. The Company records the cost of gas purchased from third
parties for the purposes of consumption in its power plants as fuel expense,
while gas purchased from third parties for hedging, balancing, and optimization
activities is recorded as purchased gas expense for hedging and optimization, a
component of oil and gas production and marketing expense. Certain hedging,
balancing and optimization activity is presented net in accordance with EITF
Issue No. 03-11. See discussion above.
Research and Development Expense -- The Company engages in research and
development ("R&D") activities through PSM. R&D activities related to the design
and manufacturing of high performance combustion system and turbine blade parts
are accounted for in accordance with SFAS No. 2, "Accounting for Research and
Development Costs." The Company's R&D expense includes costs incurred for
conceptual formulation and design of new vanes, blades, combustors and other
replacement parts for the industrial gas turbine industry.
Provision (Benefit) for Income Taxes -- Deferred income taxes are based on
the differences between the financial reporting and tax bases of assets and
liabilities. The deferred income tax provision represents the changes during the
reporting period in the deferred tax assets and deferred tax liabilities, net of
the effect of acquisitions and dispositions. Deferred tax assets include tax
losses and tax credit carryforwards and are reduced by a valuation allowance if,
based on available evidence, it is more likely than not that some portion or all
of the deferred tax assets will not be realized. Additionally, with respect to
income taxes, the Company assumes the deductibility of certain costs in its
income tax filings and estimates the future recovery of deferred tax assets. For
the twelve months ended December 31, 2004, 2003 and 2002, the Company's
effective tax rate from continuing operations was 35.9%, 56.8% and 90.1%,
respectively. Also, see Note 19 concerning the impact of tax legislation passed
October 22, 2004.
Insurance Program -- CPN Insurance Corporation, a wholly owned captive
insurance subsidiary, charges the Company premium rates to insure casualty lines
(worker's compensation, automobile liability, and general liability) as well as
all risk property insurance including business interruption. Accruals for
casualty claims under the captive insurance program are recorded on a monthly
basis, and are based upon the estimate of the total cost of the claims incurred
during the policy period. Accruals for claims under the captive insurance
program pertaining to property, including business interruption claims, are
recorded on a claims-incurred basis. In consolidation, claims are accrued on a
gross basis before deductibles. The captive provides insurance coverage with
limits up to $25 million per occurrence for property claims, including business
interruption, and up to $500,000 per occurrence for casualty claims.
Intercompany transactions between the captive insurance program and Calpine
affiliates are eliminated in consolidation.
Stock-Based Compensation -- See Note 21 for a discussion of the Company's
accounting policies for stock-based compensation.
Operational Data -- Operational data (including, but not limited to,
megawatts ("MW"), megawatt hours ("MWh"), billions cubic feet equivalent
("Bcfe") and thousand barrels ("MBbl")), throughout this Form 10-K is unaudited.
New Accounting Pronouncements
SFAS No. 144
Effective January 1, 2002, the Company adopted SFAS No. 144 "Accounting for
the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which changed
the criteria for determining when the disposal or sale of certain assets meets
the definition of "discontinued operations." Some of the Company's asset sales
in 2002, 2003 and 2004 met the requirements of the new definition and
accordingly, the Company made reclassifications to current and prior period
financial statements to reflect the sale or designation as "held for sale" of
certain oil and gas and power plant assets and liabilities and to separately
classify the operating results of the assets sold and gain on sale of those
assets from the operating results of continuing operations. See Note 10 for
further information.
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FIN 46 and FIN 46-R
In January 2003, FASB issued FIN 46. FIN 46, as originally issued, was
effective immediately for VIEs created or acquired after January 31, 2003. FIN
46 requires the consolidation of an entity by an enterprise that absorbs a
majority of the entity's expected losses, receives a majority of the entity's
expected residual returns, or both, as a result of ownership, contractual or
other financial interest in the entity. Historically, entities have generally
been consolidated by an enterprise when it has a controlling financial interest
through ownership of a majority voting interest in the entity. The objectives of
FIN 46 are to provide guidance on the identification of VIEs for which control
is achieved through means other than ownership of a majority of the voting
interest of the entity, and how to determine which business enterprise (if any),
as the Primary Beneficiary, should consolidate the VIE. This model for
consolidation applies to an entity in which either (1) the at-risk equity is
insufficient to absorb expected losses without additional subordinated financial
support or (2) its at-risk equity holders as a group are not able to make
decisions that have a significant impact on the success or failure of the
entity's ongoing activities. A variable interest in a VIE, by definition, is an
asset, liability, equity, contractual arrangement or other economic interest
that absorbs the entity's variability.
In December 2003, FASB modified FIN 46 with FIN 46-R to make certain
technical corrections and to address certain implementation issues. FIN 46-R
delayed the effective date of the interpretation to March 31, 2004, (for
calendar-year enterprises), for all non-Special Purpose Entity ("SPE") VIEs. FIN
46, as originally issued was effective as of December 31, 2003, for all
investments in SPEs. The Company has adopted FIN 46-R for its equity method
joint ventures and operating lease arrangements containing fixed price purchase
options, its wholly owned subsidiaries that are subject to long-term PPAs and
tolling arrangements and its wholly owned subsidiaries that have issued
mandatorily redeemable non-controlling preferred interests as of March 31, 2004,
and for its investments in SPEs as of December 31, 2003.
Joint Venture Investments and Operating Leases with Fixed Price Options
On application of FIN 46-R, the Company evaluated its economic interests in
joint venture investments and operating lease arrangements containing fixed
price purchase options and concluded that, in some instances, these entities
were VIEs. However, in these instances, the Company was not the Primary
Beneficiary, as the Company would not absorb a majority of these entities'
expected variability. An enterprise that holds a significant variable interest
in a VIE is required to make certain disclosures regarding the nature and timing
of its involvement with the VIE and the nature, purpose, size and activities of
the VIE. The fixed price purchase options under the Company's operating lease
arrangements were not considered significant variable interests. However, the
joint ventures in which the Company has invested, and which did not qualify for
the definition of a business scope exception outlined in paragraph 4(h) of FIN
46-R, were considered significant variable interests and the required
disclosures have been made in Note 7 for these joint venture investments.
Significant Long-Term Power Sales and Tolling Agreements
An analysis was performed for the Company's wholly owned subsidiaries with
significant long-term power sales or tolling agreements. Certain of these 100%
Company-owned subsidiaries were deemed to be VIEs by virtue of the power sales
and tolling agreements which met the definition of a variable interest under FIN
46-R. However, in all cases, the Company absorbed a majority of the entity's
variability and continues to consolidate these wholly owned subsidiaries. As
part of the Company's quantitative assessment, a fair value methodology was used
to determine whether the Company or the power purchaser absorbed the majority of
the subsidiary's variability. As part of the analysis, the Company qualitatively
determined that power sales or tolling agreements with a term for less than
one-third of the facility's remaining useful life or for less than 50% of the
entity's capacity would not cause the power purchaser to be the Primary
Beneficiary, due to the length of the economic life of the underlying assets.
Also, power sales and tolling agreements meeting the definition of a lease under
EITF Issue No. 01-08, "Determining Whether an Arrangement Contains a Lease,"
were not considered variable interests, since lease payments create rather than
absorb variability, and therefore, do not meet the definition of a variable
interest.
Preferred Interests issued from Wholly-Owned Subsidiaries
A similar analysis was performed for the Company's wholly owned
subsidiaries that have issued mandatorily redeemable non-controlling preferred
interests. These entities were determined to be VIEs in which the Company
absorbs the majority of the variability, primarily due to the debt
characteristics of the preferred interest, which are classified as debt in
accordance with SFAS No. 150, in the Company's Consolidated Balance Sheets. As a
result, the Company continues to consolidate these wholly owned subsidiaries.
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Investments in Special Purpose Entities
Significant judgment was required in making an assessment of whether or not
a VIE was an SPE for purposes of adopting and applying FIN 46, as originally
issued at December 31, 2003. Since the current accounting literature does not
provide a definition of an SPE, the Company's assessment was primarily based on
the degree to which the VIE aligned with the definition of a business outlined
in FIN 46-R. Entities that meet the definition of a business outlined in FIN
46-R and that satisfy other formation and involvement criteria are not subject
to the FIN 46-R consolidation guidelines. The definitional characteristics of a
business include having: inputs such as long-lived assets; the ability to obtain
access to necessary materials and employees; processes such as strategic
management, operations and resource management; and the ability to obtain access
to the customers that purchase the outputs of the entity. Based on this
assessment, the Company determined that six VIE investments were in SPEs
requiring further evaluation and were subject to the application of FIN 46, as
originally issued, as of December 31, 2003: Calpine Northbrook Energy Marketing,
LLC ("CNEM"), Power Contract Financing, L.L.C. ("PCF"), Power Contract Financing
III, LLC ("PCF III") and Trust I, Trust II and Trust III (collectively, the
"Trusts").
On May 15, 2003, the Company's wholly owned subsidiary, CNEM, completed the
$82.8 million monetization of an existing power sales agreement with the
Bonneville Power Administration ("BPA"). CNEM borrowed $82.8 million secured by
the spread between the BPA contract and certain fixed power purchase contracts.
CNEM was established as a bankruptcy-remote entity and the $82.8 million loan is
recourse only to CNEM's assets and is not guaranteed by the Company. CNEM was
determined to be a VIE in which the Company was the Primary Beneficiary.
Accordingly, the entity's assets and liabilities were consolidated into the
Company's accounts as of June 30, 2003.
On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of CES,
completed an offering of two tranches of Senior Secured Notes Due 2006 and 2010
(collectively called the "PCF Notes"), totaling $802.2 million. To facilitate
the transaction, the Company formed PCF as a wholly owned, bankruptcy remote
entity with assets and liabilities consisting of certain transferred power
purchase and sales contracts, which serve as collateral for the PCF Notes. The
PCF Notes are non-recourse to the Company's other consolidated subsidiaries. PCF
was determined to be a VIE in which the Company was the Primary Beneficiary.
Accordingly, the entity's assets and liabilities were consolidated into the
Company's accounts as of June 30, 2003.
Upon the application of FIN 46, as originally issued at December 31, 2003,
for the Company's investments in SPEs, the Company determined that its equity
investment in the Trusts was not considered at-risk as defined in FIN 46 and
that the Company did not have a significant variable interest in the Trusts.
Consequently, the Company deconsolidated the Trusts as of December 31, 2003.
In addition, as a result of the debt reserve monetization consummated on
June 2, 2004, the Company was required to evaluate its new investments in the
PCF and PCF III entities under FIN 46-R (effective March 31, 2004). The Company
determined that the entities were VIEs but the Company was not the Primary
Beneficiary and was, therefore, required to deconsolidate the entities as of
June 30, 2004.
The Company created CNEM, PCF, PCF III and the Trusts to facilitate capital
transactions. However, in cases such as this where the Company has continuing
involvement with the assets held by the deconsolidated SPE, the Company accounts
for the capital transaction with the SPE as a financing rather than a sale under
EITF Issue No. 88-18, "Sales of Future Revenue" ("EITF Issue No. 88-18") or SFAS
No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities -- a Replacement of FASB Statement No. 125"
("SFAS No. 140"), as appropriate. When EITF Issue No. 88-18 and SFAS No. 140
require the Company to account for a transaction as a financing, derecognition
of the assets underlying the financing is prohibited, and the proceeds received
from the transaction must be recorded as debt. Accordingly, in situations where
the Company accounts for transactions as financings under EITF Issue No. 88-18
or SFAS No. 140, the Company continues to recognize the assets and the debt of
the deconsolidated SPE on its balance sheet. The table below summarizes how the
Company has accounted for its SPEs when it has continuing involvement under EITF
Issue No. 88-18 or SFAS No. 140:
FIN 46-R Sale or
Treatment Financing
------------- ---------
CNEM................................................ Consolidate N/A
PCF................................................. Deconsolidate Financing
PCF III............................................. Deconsolidate Financing
Trust I, Trust II and Trust III..................... Deconsolidate Financing
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EITF Issue No. 04-07
An integral part of applying FIN 46-R is determining which economic
interests are variable interests. In order for an economic interest to be
considered a variable interest, it must "absorb variability" of changes in the
fair value of the VIE's underlying net assets. Questions have arisen regarding
(a) how to determine whether an interest absorbs variability, and (b) whether
the nature of how a long position is created, either synthetically through
derivative transactions or through cash transactions, should affect the
assessment of whether an interest is a variable interest. EITF Issue No. 04-07,
"Determining Whether an Interest Is a Variable Interest in a Potential Variable
Interest Entity" ("EITF Issue No. 04-07") is still in the discussion phase, but
will eventually provide a model to assist in determining whether an economic
interest in a VIE is a variable interest. The Task Force's discussions on this
Issue have centered on if the variability should be based on whether (a) the
interest absorbs fair value variability, (b) the interest absorbs cash flow
variability, or (c) the interest absorbs both fair value and cash flow
variability. While a consensus has not been reached, a majority of the Task
Force members generally support an approach that would determine predominant
variability based on the nature of the operations of the VIE. Under this view,
for financial VIEs a presumption would exist that only interests that absorb
fair value variability would be considered variable interests. Conversely, for
non-financial (or operating) VIEs, a presumption would exist that only interests
that absorb cash flow variability would be considered variable interests. The
final conclusions reached on this issue may impact the Company's methodology
used in making quantitative and/or qualitative assessments of the variability
absorbed by the different economic interests holders in the VIE's in which the
Company holds a variable interest. However, until the EITF reaches a final
consensus, the effects of this issue on the Company's financial statements is
indeterminable.
EITF Issue No. 04-08
On September 30, 2004, the EITF reached a final consensus on EITF Issue No.
04-08, "The Effect of Contingently Convertible Debt on Diluted Earnings per
Share" ("EITF Issue No. 04-08"). The guidance in EITF Issue No. 04-08 is
effective for periods ending after December 15, 2004, and must be applied by
retroactively restating previously reported earnings per share ("EPS") results.
The consensus requires companies that have issued contingently convertible
instruments with a market price trigger to include the effects of the conversion
in diluted EPS (if dilutive), regardless of whether the price trigger had been
met. Prior to this consensus, contingently convertible instruments were not
included in diluted EPS if the price trigger had not been met. Typically, the
affected instruments are convertible into common stock of the issuer after the
issuer's common stock price has exceeded a predetermined threshold for a
specified time period. Calpine's $634 million of 4.75% Contingent Convertible
Senior Notes Due 2023 ("2023 Convertible Senior Notes") and $736 million
aggregate principal amount at maturity of Contingent Convertible Notes Due 2014
("2014 Convertible Notes") outstanding at December 31, 2004, are affected by the
new guidance. Depending on the closing price of the Company's common stock at
the end of each reporting period, the conversion provisions in these Contingent
Convertible Notes may significantly impact the reported diluted EPS amounts in
future periods.
For the twelve months ended December 31, 2004, approximately 8.6 million
weighted common shares potentially issuable under the Company's outstanding 2014
Contingent Convertible Notes were excluded from the diluted earnings per share
calculations as the inclusion of such shares would have been antidilutive
because of the Company's net loss. The 2023 Convertible Senior Notes would not
have impacted the diluted EPS calculation for any reporting period since
issuance in November 2003, because the Company's closing stock price at each
period end was below the conversion price.
SFAS No. 128-R
FASB is expected to revise SFAS No. 128, "Earnings Per Share" ("SFAS No.
128") to make it consistent with International Accounting Standard No. 33,
"Earnings Per Share," so that EPS computations will be comparable on a global
basis. This new guidance is expected to be issued by the end of 2005 and will
require restatement of prior periods diluted EPS data. The proposed changes will
affect the application of the treasury stock method and contingently issuable
(based on conditions other than market price) share guidance for computing
year-to-date diluted EPS. In addition to modifying the year-to-date calculation
mechanics, the proposed revision to SFAS No. 128 would eliminate a company's
ability to overcome the presumption of share settlement for those instruments or
contracts that can be settled, at the issuer or holder's option, in cash or
shares. Under the revised guidance, FASB has indicated that any possibility of
share settlement other than in an event of bankruptcy will require a presumption
of share settlement when calculating diluted EPS. The Company's 2023 Convertible
Senior Notes and 2014 Convertible Notes contain provisions that would require
share settlement in the event of conversion under certain limited events of
default, including bankruptcy. Additionally, the 2023 Convertible Senior Notes
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include a provision allowing the Company to meet a put with either cash or
shares of stock. The revised guidance, if not amended before final issuance,
would increase the potential dilution to the Company's EPS, particularly when
the price of the Company's common stock is low, since the more dilutive of
calculations would be used considering both:
(i) normal conversion assuming a combination of cash and a variable number of
shares; and
(ii) conversion during certain limited events of default assuming 100% shares at
the fixed conversion rate, or, in the case of the 2023 Convertible Senior
Notes, meeting a put entirely with shares of stock.
EITF Issue No. 03-13
At the November 2004 EITF meeting, the final consensus was reached on EITF
Issue No. 03-13, "Applying the Conditions in Paragraph 42 of FASB Statement No.
144 in Determining Whether to Report Discontinued Operations" ("EITF Issue No.
03-13"). This Issue is effective prospectively for disposal transactions entered
into after January 1, 2005, and provides a model to assist in evaluating (a)
which cash flows should be considered in the determination of whether cash flows
of the disposal component have been or will be eliminated from the ongoing
operations of the entity and (b) the types of continuing involvement that
constitute significant continuing involvement in the operations of the disposal
component. The Company considered the model outlined in EITF Issue No. 03-13 in
its evaluation of the September 2004 sale of the Canadian and Rockies oil and
gas reserves and the Company's commitment to a plan of divestiture of its
remaining oil and gas assets and the Saltend Energy Centre in the three months
ended June 30, 2005 (see Note 10 for more information regarding these
dispositions). The final consensus did not change the Company's original
conclusions reached under the existing discontinued operations guidance in SFAS
No. 144.
EITF Issue No. 03-06
In March 2004, the EITF reached a final consensus on EITF Issue No. 03-06,
"Participating Securities and the Two -- Class Method under FASB Statement No.
128, Earnings per Share," ("EITF Issue No. 03-06") effective for reporting
period beginning after March 31, 2004. EITF Issue No. 03-06 clarifies the
definition of a participating security under SFAS No. 128 and how to apply the
two-class method of computing EPS once it is determined that a security is
participating, including how to allocate undistributed earnings to such a
security. Prior to the issuance of EITF Issue No. 03-06, the Company had issued
certain convertible debt instruments with features that may have been considered
participating under SFAS No. 128. However, under the clarifying guidance of EITF
Issue No. 03-06, none of these features created a "participating security."
Adoption of this pronouncement did not impact the Company's current or
historical reported EPS amounts.
EITF Issue No. 04-10
In October 2004, FASB ratified EITF Issue No. 04-10, "Determining Whether
to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds"
("EITF Issue No. 04-10"). This issue addresses how an entity should evaluate the
aggregation criteria in paragraph 17 of SFAS No. 131 "Disclosures about Segments
of an Enterprise and Related Information" ("SFAS No. 131") when determining
whether operating segments that do not meet the quantitative thresholds may be
aggregated in accordance with paragraph 19 of SFAS No. 131. The Task Force
reached a consensus that operating segments must always have similar economic
characteristics and meet a majority of the remaining five aggregation criteria,
items (a)-(e), listed in paragraph 17, in order to be aggregated under paragraph
19. The consensus was originally effective for reporting periods ending December
31, 2004, with the corresponding information for earlier periods, including
interim periods, restated unless it is impractical to do so. At the November
2004 EITF meeting, the Task Force delayed the effective date of this Issue to
coincide with the effective date of the anticipated FASB Staff Position on the
meaning of "similar economic characteristics." EITF Issue No. 04-10 is not
expected to impact the Company's current approach to segment reporting or its
historically reported segment results.
SFAS No. 123-R
In December 2004, FASB issued SFAS No. 123 (revised 2004) ("SFAS No.
123-R"), "Share Based Payments." This Statement revises SFAS No. 123,
"Accounting for Stock-Based Compensation" ("SFAS No. 123") and supersedes
Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued
to Employees" ("APB Opinion No. 25"), and its related implementation guidance.
This statement requires a public entity to measure the cost of employee services
received in exchange for an award of equity instruments based on the grant-date
fair value of the award (with limited exceptions), which must be recognized over
the period during which an employee is required to provide service in exchange
for the award -- the requisite service period (usually the vesting period). The
statement applies to all share-based payment transactions in which an entity
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acquires goods or services by issuing (or offering to issue) its shares, share
options, or other equity instruments or by incurring liabilities to an employee
or other supplier (a) in amounts based, at least in part, on the price of the
entity's shares or other equity instruments or (b) that require or may require
settlement by issuing the entity's equity shares or other equity instruments.
The statement requires the accounting for any excess tax benefits to be
consistent with the existing guidance under SFAS No. 123, which provides a
two-transaction model summarized as follows:
o If settlement of an award creates a tax deduction that exceeds
compensation cost, the additional tax benefit would be recorded as a
contribution to paid-in-capital.
o If the compensation cost exceeds the actual tax deduction, the
write-off of the unrealized excess tax benefits would first reduce any
available paid-in capital arising from prior excess tax benefits, and
any remaining amount would be charged against the tax provision in the
income statement.
The Company is still evaluating the impact of adopting and subsequently
accounting for excess tax benefits under the two-transaction model described in
SFAS No. 123, but does not expect its consolidated net income or financial
position to be materially affected upon adoption of SFAS No. 123-R.
The statement also amends SFAS No. 95, "Statement of Cash Flows," to
require that excess tax benefits be reported as a financing cash inflow rather
than as an operating cash inflow. However, the statement does not change the
accounting guidance for share-based payment transactions with parties other than
employees provided in SFAS No. 123 as originally issued and EITF Issue No.
96-18, "Accounting for Equity Instruments That Are Issued to Other Than
Employees for Acquiring, or in Conjunction with Selling, Goods or Services."
Further, this statement does not address the accounting for employee share
ownership plans, which are subject to AICPA Statement of Position 93-6,
"Employers' Accounting for Employee Stock Ownership Plans."
The statement applies to all awards granted, modified, repurchased, or
cancelled after July 1, 2005, and to the unvested portion of all awards granted
prior to that date. Public entities that used the fair-value-based method for
either recognition or disclosure under SFAS No. 123 may adopt this Statement
using a modified version of prospective application (modified prospective
application). Under modified prospective application, compensation cost for the
portion of awards for which the employee's requisite service has not been
rendered that are outstanding as of July 1, 2005 must be recognized as the
requisite service is rendered on or after that date. The compensation cost for
that portion of awards shall be based on the original grant-date fair value of
those awards as calculated for recognition under SFAS No. 123. The compensation
cost for those earlier awards shall be attributed to periods beginning on or
after July 1, 2005 using the attribution method that was used under SFAS No.
123. Furthermore, the method of recognizing forfeitures must now be based on an
estimated forfeiture rate and can no longer be based on forfeitures as they
occur.
Adoption of SFAS No. 123-R is not expected to materially impact the
Company's consolidated results of operations, cash flows or financial position,
due to the Company's prior adoption of SFAS No. 123 as amended by SFAS No. 148,
"Accounting for Stock-Based Compensation -- Transition and Disclosure," ("SFAS
No. 148") on January 1, 2003. SFAS No. 148 allowed companies to adopt the
fair-value-based method for recognition of compensation expense under SFAS No.
123 using prospective application. Under that transition method, compensation
expense was recognized in the Company's Consolidated Statement of Operations
only for stock-based compensation granted after the adoption date of January 1,
2003. Furthermore, as we have chosen the multiple option approach in recognizing
compensation expense associated with the fair value of each option granted,
nearly 80% of the total fair value of the stock option is recognized by the end
of the second year of the vesting period, and therefore remaining compensation
expense associated with options granted before January 1, 2003, is expected to
be immaterial.
SFAS No. 151
In November 2004, FASB issued SFAS No. 151, "Inventory Costs, an amendment
of ARB No. 43, Chapter 4" ("SFAS No. 151"). This Statement amends the guidance
in ARB No. 43, Chapter 4, "Inventory Pricing," to clarify the accounting for
abnormal amounts of idle facility expense, freight, handling costs, and wasted
material (spoilage). Paragraph 5 of ARB 43, Chapter 4, previously stated that ".
.. . under some circumstances, items such as idle facility expense, excessive
spoilage, double freight, and rehandling costs may be so abnormal as to require
treatment as current period charges. . . ." This Statement requires those items
to be recognized as a current-period charge regardless of whether they meet the
criterion of "so abnormal." In addition, this Statement requires that allocation
of fixed production overheads to the costs of conversion be based on the normal
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capacity of the production facilities. The provisions of SFAS No. 151 are
applicable to inventory costs incurred during fiscal years beginning after June
15, 2005. Adoption of this statement is not expected to materially impact the
Company's consolidated results of operations, cash flows or financial position.
SFAS No. 153
In December 2004, FASB issued SFAS No. 153 ("SFAS No. 153"), "Exchanges of
Nonmonetary Assets." This standard eliminates the exception in APB Opinion No.
29, "Accounting for Nonmonetary Transactions" ("APB Opinion No. 29") for
nonmonetary exchanges of similar productive assets and replaces it with a
general exception for exchanges of nonmonetary assets that do not have
commercial substance. It requires exchanges of productive assets to be accounted
for at fair value, rather than at carryover basis, unless (1) neither the asset
received nor the asset surrendered has a fair value that is determinable within
reasonable limits or (2) the transaction lacks commercial substance (as
defined). A nonmonetary exchange has commercial substance if the future cash
flows of the entity are expected to change significantly as a result of the
exchange.
The new standard will not apply to the transfers of interests in assets in
exchange for an interest in a joint venture and amends SFAS No. 66, "Accounting
for Sales of Real Estate" ("SFAS No. 66"), to clarify that exchanges of real
estate for real estate should be accounted for under APB Opinion No. 29. It also
amends SFAS No. 140, to remove the existing scope exception relating to
exchanges of equity method investments for similar productive assets to clarify
that such exchanges are within the scope of SFAS No. 140 and not APB Opinion No.
29. SFAS No. 153 is effective for nonmonetary asset exchanges occurring in
fiscal periods beginning after June 15, 2005. Adoption of this statement is not
expected to materially impact the Company's consolidated results of operations,
cash flows or financial position.
3. Available-for-Sale Debt Securities
Collateral Debt Securities
At December 31, 2003, the Company owned held-to-maturity debt securities
that were pledged as collateral to support the King City operating lease and
that matured serially in amounts equal to a portion of the semi-annual lease
payments. At December 31, 2003, the amortized cost of these securities was $82.6
million, which represented the book value of the instruments when the Company
accounted for the securities as held-to-maturity. In the first quarter of 2004,
the Company reclassified the securities that served as collateral under the
original lease from held-to-maturity to available-for-sale in accordance with
SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
("SFAS No. 115"). As a result of the reclassification from held-to-maturity to
available-for-sale, the Company accounted for these securities at fair value for
the duration of 2004 until the instruments were liquidated. On May 19, 2004, the
Company restructured the King City operating lease. See Note 13 for more
information regarding the King City restructuring. At the close of the
restructuring transaction, the Company sold the securities for total proceeds of
$95.4 million and recorded a pre-tax gain of $12.3 million in the Other Income.
Also, in contemplation of the sale, the Company entered into an interest rate
swap with a financial institution with the intent to hedge against a decline in
value of the collateral debt securities. The swap did not meet the required
criteria for hedge effectiveness under SFAS No. 133 and, as a result, the
Company recorded all changes in the swap's fair value between the dates of
inception and settlement in the Other Income. Upon settlement of the swap, the
Company had recognized a cumulative gain of $5.2 million, which was also
recorded in the Other Income.
HIGH TIDES Securities Held
Between September 2003 and July 2004, the Company exchanged approximately
15.0 million shares of Calpine common stock in privately negotiated transactions
for approximately $77.5 million par value of HIGH TIDES I and 15.8 million
shares of Calpine common stock in privately negotiated transactions for
approximately $75.0 million par value of HIGH TIDES II. On October 20, 2004, the
Company repaid the convertible subordinate debentures held by Trust I and Trust
II, which used those proceeds to redeem the outstanding 5 3/4% convertible
preferred securities ("HIGH TIDES I") issued by Trust I, and 5 1/2% convertible
preferred securities ("HIGH TIDES II") issued by Trust II. The redemption price
paid per each $50 principal amount of such convertible preferred securities was
$50 plus accrued and unpaid distributions to the redemption date in the amount
of $0.6309 per unit with respect to the convertible preferred securities issued
by Trust I and $0.6035 per unit with respect to the convertible preferred
securities issued by Trust II. See Note 12 for further information on the
convertible subordinate debentures. The redemption of the HIGH TIDES I and HIGH
TIDES II available-for-sale securities previously purchased and held by the
Company resulted in a realized gain of approximately $6.1 million. Calpine
intends to cause both Trusts, which are related parties, to be terminated.
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On September 30, 2004, the Company repurchased par value of $115.0 million
HIGH TIDES III for cash of $111.6 million. Due to the deconsolidation of the
Trusts upon the adoption of FIN 46 as of December 31, 2003, and the terms of the
underlying debentures, the repurchased HIGH TIDES III preferred securities could
not be offset against the convertible subordinated debentures and are accounted
for as available for sale securities and recorded in Other Assets at fair market
value at December 31, 2004, with the difference from their repurchase price
recorded in OCI (in thousands):
December 31, 2004
------------------------------------------------------------------
Gross Unrealized
Gains in Other Realized
Repurchase Comprehensive Gains on
Price(1) Income/ (Loss) Redemption Redemptions Fair Value
---------- ---------------- ---------- ----------- ----------
HIGH TIDES I............................................... $ 75,020 $ -- $ 2,480 $ (77,500) $ --
HIGH TIDES II.............................................. 71,341 -- 3,659 (75,000) --
HIGH TIDES III............................................. 110,592 958 -- -- $111,550
------- ------- --------- --------
$ 958 $ 6,139 $ 152,500) $111,550
======= ======= ========= ========
- ------------
<FN>
(1) The repurchase price is shown net of accrued interest. The repurchased
amount for HIGH TIDES I was $75.4 million less $0.4 million of accrued
interest. The repurchased amount for HIGH TIDES II was $72.0 million less
$0.7 million of accrued interest. The repurchased amount for HIGH TIDES III
was $111.6 million less $1 million of accrued interest.
</FN>
4. Property, Plant and Equipment, Net, and Capitalized Interest
As of December 31, 2004 and 2003, the components of property, plant and
equipment, are stated at cost less accumulated depreciation and depletion as
follows (in thousands):
2004 2003
-------------- -------------
Buildings, machinery, and equipment............. $ 15,214,698 $ 11,994,212
Oil and gas properties, including pipelines..... 90,625 130,276
Geothermal properties........................... 474,869 460,602
Other........................................... 208,614 225,584
------------- -------------
15,988,806 12,810,674
Less: Accumulated depreciation and depletion.... (1,476,335) (1,058,244)
------------- -------------
14,512,471 11,752,430
Land............................................ 104,972 94,930
Construction in progress........................ 4,321,977 5,762,132
------------- -------------
Property, plant and equipment, net.............. $ 18,939,420 $ 17,609,492
============= =============
Total depreciation and depletion expense for the years ended December 31,
2004, 2003 and 2002 was $482.8 million, $418.7 million and $302.3 million,
respectively.
The Company has various debt instruments that are secured by certain of its
property, plant and equipment. See Notes 11-18 for a detailed discussion of such
instruments.
Buildings, Machinery, and Equipment
This component primarily includes electric power plants and related
equipment. Depreciation is recorded utilizing the straight-line method over the
estimated original composite useful life, generally 35 years for baseload power
plants, exclusive of the estimated salvage value, typically 10%. Peaking
facilities are generally depreciated over 40 years, less the estimated salvage
value of 10%. The Company capitalizes costs for major turbine generator
refurbishments for the "hot gas path section" and compressor components, which
include such significant items as combustor parts (e.g. fuel nozzles, transition
pieces, and "baskets") compressor blades, vanes and diaphragms. These
refurbishments are done either under long term service agreements by the
original equipment manufacturer or by Calpine's Turbine Maintenance Group. The
capitalized costs are depreciated over their estimated useful lives ranging from
2 to 14 years. At December 31, 2004, the weighted average life was approximately
6 years. The Company expenses annual planned maintenance. Included in buildings,
machinery and equipment are assets under capital leases. See Note 13 for more
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information regarding these assets under capital leases. Certain capital
improvements associated with leased facilities may be deemed to be leasehold
improvements and are amortized over the shorter of the term of the lease or the
economic life of the capital improvement.
Oil and Gas Properties
On July 7, 2005, the Company, along with its subsidiaries, Calpine Gas
Holdings LLC and Calpine Fuels Corporation, sold substantially all of its
remaining domestic oil and gas assets to Rosetta Resources Inc. for $1.05
billion, less certain transaction fees and expenses. See Note 10 for more
information on this transaction. The assets underlying the transaction gualified
as discontinued operations in the three months ended June 30, 2005. The
following information relates to the Company's historical accounting for its oil
and gas properties.
The Company follows the successful efforts method of accounting for oil and
natural gas activities. Under the successful efforts method, lease acquisition
costs and all development costs are capitalized. Exploratory drilling costs are
capitalized until the results are determined. If proved reserves are not
discovered, the exploratory drilling costs are expensed. Other exploratory costs
are expensed as incurred. Interest costs related to financing major oil and gas
projects in progress are capitalized until the projects are evaluated or until
the projects are substantially complete and ready for their intended use if the
projects are evaluated as successful. The provision for depreciation, depletion,
and amortization is based on the capitalized costs as determined above, plus
future abandonment costs net of salvage value, using the units of production
method with lease acquisition costs amortized over total proved reserves and
other costs amortized over proved developed reserves.
The Company assesses the impairment for oil and gas properties periodically
(at least annually) to determine if impairment of such properties is necessary.
Management utilizes its year-end reserve report prepared by a licensed
independent petroleum engineering firm and related market factors to estimate
the future cash flows for all proved developed (producing and non-producing) and
proved undeveloped reserves. Property impairments may occur if a field discovers
lower than anticipated reserves, reservoirs produce below original estimates or
if commodity prices fall below a level that significantly affects anticipated
future cash flows on the property. Proved oil and gas property values are
reviewed when circumstances suggest the need for such a review and, if required,
the proved properties are written down to their estimated fair value based on
proved reserves and other market factors. Unproved properties are reviewed
quarterly to determine if there has been impairment of the carrying value, with
any such impairment charges to expense in the current period. As a result of
decreases in proved undeveloped reserves located in South Texas and proved
developed non-producing reserves in Offshore Gulf of Mexico, a non-cash
impairment charge of approximately $202.1 was recorded for the year ended
December 31, 2004, and has been reclassified to discontinued operations. For the
years ended December 31, 2003 and 2002, the impairment charge reclassified to
discontinued operations was $2.9 million and $3.4 million, respectively. These
charges related exclusively to the Oil and Gas Production and Marketing segment.
Geothermal Properties
The Company capitalizes costs incurred in connection with the development
of geothermal properties, including costs of drilling wells and overhead
directly related to development activities as well as costs of production
equipment, the related facilities and the operating power plants. Proceeds from
the sale of geothermal properties are applied against capitalized costs, with no
gain or loss recognized.
Geothermal costs, including an estimate of future costs to be incurred,
costs to optimize the productivity of the assets, and the estimated costs to
dismantle, are amortized by the units of production method based on the
estimated total productive output over the estimated useful lives of the related
steam fields. Depreciation of the buildings and roads is computed using the
straight-line method over their estimated useful lives. It is reasonably
possible that the estimate of useful lives, total unit-of-production or total
capital costs to be amortized using the units-of-production method could differ
materially in the near term from the amounts assumed in arriving at current
depreciation expense. These estimates are affected by such factors as the
ability of the Company to continue selling electricity to customers at estimated
prices, changes in prices of alternative sources of energy such as
hydro-generation and gas, and changes in the regulatory environment. Geothermal
steam turbine generator refurbishments are expensed as incurred.
Other
This component primarily includes software and emission reduction credits
("ERCs"). Software is amortized over its estimated useful life, generally 3 to 5
years. The Company holds ERCs that must generally be acquired during the
permitting process for power plants in construction. ERCs are related to
reductions in environmental emissions that result from some action like
increasing energy efficiency, and are measured and registered in a way so that
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they can be bought, sold, and traded. The lives of the ERCs are usually
consistent with the life of the related plant. The gross ERC balance recorded in
property, plant and equipment and included in "Other" above was $103.6 million
and $104.8 million as of December 31, 2004 and 2003, respectively. Of this
balance $21.3 million and $21.3 million related to plants in operation as of
December 31, 2004 and 2003, respectively. The depreciation expense recorded in
2004, 2003 and 2002, related to ERCs was $0.5 million, $0.5 million and $0.4
million, respectively.
Construction in Progress
CIP is primarily attributable to gas-fired power projects under
construction including prepayments on gas and steam turbine generators and other
long lead-time items of equipment for certain development projects not yet in
construction. Upon commencement of plant operation, these costs are transferred
to the applicable property category, generally buildings, machinery and
equipment.
Capital Spending -- Development and Construction
CIP, development costs in process and unassigned equipment consisted of the
following at December 31, 2004 (in thousands):
Equipment Project
# of Included in Development Unassigned
Projects CIP CIP Costs Equipment
-------- ---------- ----------- ----------- ----------
Projects in construction(1)............................................ 10 $3,194,530 $ 1,094,490 $ -- $ --
Projects in advanced development....................................... 10 670,806 520,036 102,829 --
Projects in suspended development...................................... 6 421,547 168,985 38,398 --
Projects in early development.......................................... 2 -- -- 8,952 --
Other capital projects................................................. NA 35,094 -- -- --
Unassigned equipment................................................... NA -- -- -- 66,073
---------- ----------- ---------- -------
Total construction and development costs............................. $4,321,977 $ 1,783,511 $ 150,179 $ 6,073
========== =========== =========== =======
- ------------
<FN>
(1) The Company has a total of 11 projects in construction. This includes the
10 projects above that are recorded in CIP and 1 project that is recorded
in investments in power projects. Construction activities and the
capitalization of interest on one of the construction projects has been
suspended or delayed due to current market conditions. The CIP balance on
this project was $461.5 million as of December 31, 2004. Subsequent to
December 31, 2004, construction activities and the capitalization of
interest on two additional construction projects was suspended or delayed.
Total CIP on these two projects was $683.0 million as of December 31, 2004.
</FN>
Projects in Construction -- The 10 projects in construction are projected
to come on line from March 2005 to November 2007 or later. These projects will
bring on line approximately 4,656 MW of base load capacity (5,264 MW with
peaking capacity). Interest and other costs related to the construction
activities necessary to bring these projects to their intended use are being
capitalized, unless work has been suspended, in which case capitalization of
interest expense is suspended until active construction resumes. At December 31,
2004, the estimated funding requirements to complete these projects, net of
expected project financing proceeds, is approximately $84.6 million.
Projects in Advanced Development -- There are an additional 10 projects in
advanced development. These projects will bring on line approximately 5,307 MW
of base load capacity (6,095 MW with peaking capacity). Interest and other costs
related to the development activities necessary to bring these projects to their
intended use are being capitalized. However, the capitalization of interest has
been suspended on 2 projects for which development activities are substantially
complete but construction will not commence until a PPA and financing are
obtained. The estimated cost to complete the 10 projects in advanced development
is approximately $3.0 billion. The Company's current plan is to finance these
project costs as PPAs are arranged.
Suspended Development Projects -- Due to current electric market
conditions, we have ceased capitalization of additional development costs and
interest expense on certain development projects on which work has been
suspended. Capitalization of costs may recommence as work on these projects
resumes, if certain milestones and criteria are met indicating that it is again
highly probable that the costs will be recovered through future operations. As
is true for all projects, the suspended projects are reviewed for impairment
whenever there is an indication of potential reduction in a project's fair
value. Further, if it is determined that it is no longer probable that the
projects will be completed and all capitalized costs recovered through future
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operations, the carrying values of the projects would be written down to their
recoverable value. These projects would bring on line approximately 2,956 MW of
base load capacity (3,409 MW with peaking capacity). The estimated cost to
complete these projects is approximately $1.8 billion.
Projects in Early Development -- Costs for projects that are in early
stages of development are capitalized only when it is highly probable that such
costs are ultimately recoverable and significant project milestones are
achieved. Until then all costs, including interest costs, are expensed. The
projects in early development with capitalized costs relate to two projects and
include geothermal drilling costs and equipment purchases.
Other Capital Projects -- Other capital projects primarily consist of
enhancements to operating power plants, geothermal resource and facilities
development, as well as software developed for internal use.
Unassigned Equipment -- As of December 31, 2004, the Company had made
progress payments on 4 turbines and other equipment with an aggregate carrying
value of $66.1 million. This unassigned equipment is classified on the balance
sheet as other assets because it is not assigned to specific development and
construction projects. The Company is holding this equipment for potential use
on future projects. It is possible that some of this unassigned equipment may
eventually be sold, potentially in combination with the Company's engineering
and construction services. For equipment that is not assigned to development or
construction projects, interest is not capitalized.
Capitalized Interest -- The Company capitalizes interest on capital
invested in projects during the advanced stages of development and the
construction period in accordance with SFAS No. 34, "Capitalization of Interest
Cost," ("SFAS No. 34") as amended by SFAS No. 58, "Capitalization of Interest
Cost in Financial Statements That Include Investments Accounted for by the
Equity Method (an Amendment of FASB Statement No. 34)." The Company's qualifying
assets include CIP, certain oil and gas properties under development,
construction costs related to unconsolidated investments in power projects under
construction, advanced stage development costs, as well as such above mentioned
assets classified as held for sale. For the years ended December 31, 2004, 2003
and 2002, the total amount of interest capitalized was $376.1 million, $444.5
million and $575.5 million, including $49.1 million, $66.0 million and $114.2
million, respectively, of interest incurred on funds borrowed for specific
construction projects and $327.0 million, $378.5 million and $461.3 million,
respectively of interest incurred on general corporate funds used for
construction. Upon commencement of plant operation, capitalized interest, as a
component of the total cost of the plant, is amortized over the estimated useful
life of the plant. The decrease in the amount of interest capitalized during the
year ended December 31, 2004 reflects the completion of construction for several
power plants, the suspension of certain of the Company's development and
construction projects, and a reduction in the Company's development and
construction program in general.
In accordance with SFAS No. 34, the Company determines which debt
instruments best represent a reasonable measure of the cost of financing
construction assets in terms of interest cost incurred that otherwise could have
been avoided. These debt instruments and associated interest cost are included
in the calculation of the weighted average interest rate used for capitalizing
interest on general funds. The primary debt instruments included in the rate
calculation of interest incurred on general corporate funds are the Company's
Senior Notes, the Company's term loan facilities and the secured working capital
revolving credit facility.
Impairment Evaluation -- All construction and development projects and
unassigned turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for impairment separately, as it is integral to the assumed future
operations of the project to which it is assigned. If it is determined that it
is no longer probable that the projects will be completed and all capitalized
costs recovered through future operations, the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144. The Company reviews its unassigned equipment for potential
impairment based on probability-weighted alternatives of utilizing the equipment
for future projects versus selling the equipment. Utilizing this methodology,
the Company does not believe that the equipment held for use is impaired.
However, during the year ended December 31, 2004, the Company recorded to the
"Equipment cancellation and impairment cost" line of the Consolidated Statement
of Operations $3.2 million in net losses in connection with equipment sales.
During the year ended December 31 2003, the Company recorded to the same line
$29.4 million in losses in connection with the sale of four turbines, and it may
incur further losses should it decide to sell more unassigned equipment in the
future.
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Asset Retirement Obligations
The Company adopted SFAS No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS No. 143") on January 1, 2003. As required by the new rules,
the Company recorded liabilities equal to the present value of expected future
asset retirement obligations at January 1, 2003. The Company identified
obligations related to operating gas-fired power plants, geothermal power plants
and oil and gas properties. The liabilities are partially offset by increases in
net assets recorded as if the provisions of SFAS No. 143 had been in effect at
the date the obligation was incurred, which for power plants is generally the
start of construction, typically building up during construction until
commercial operations for the facility is achieved.
The information below reconciles the values of the asset retirement
obligation related to the Company's continuing operatons from the date the
liability was recorded (in thousands):
Total
----------
Asset retirement obligation at January 1, 2003..................... $ 24,028
Liabilities incurred............................................. 3,951
Liabilities settled.............................................. (1,276)
Accretion expense................................................ 2,686
Revisions in the estimated cash flows............................ 2,493
Other (primarily foreign currency translation)................... (7,014)
----------
Asset retirement obligation at December 31, 2003................... $ 24,868
Liabilities incurred............................................. 3,528
Liabilities settled.............................................. (324)
Accretion expense................................................ 5,174
Revisions in the estimated cash flows............................ --
Other (primarily foreign currency translation)................... (1,896)
----------
Asset retirement obligation at December 31, 2004................... $ 31,350
==========
5. Goodwill and Other Intangible Assets
On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," ("SFAS No. 142") which requires that all intangible assets
with finite useful lives be amortized and that goodwill and intangible assets
with indefinite lives not be amortized, but rather tested upon adoption and at
least annually for impairment. The Company completed its annual goodwill
impairment test as required under SFAS No. 142 and determined that the fair
value of the reporting units with goodwill exceeded their net carrying values.
Therefore, the Company's goodwill asset was not impaired as of December 31,
2004. Subsequent goodwill impairment tests will be performed, at a minimum, in
December of each year, in conjunction with the Company's annual reporting
process.
In accordance with the standard, the Company discontinued the amortization
of its recorded goodwill as of January 1, 2002, identified reporting units based
on its current segment reporting structure and allocated all recorded goodwill,
as well as other assets and liabilities, to the reporting units. The entire
balance of goodwill was assigned to the PSM reporting unit, which is included in
the Corporate, Other and Eliminations reporting segment as defined by SFAS No.
131. Recorded goodwill, by reporting segment, as of December 31, 2003, was (in
thousands):
2004 2003
---------- ----------
Electric Generation and Marketing...................... $ -- $ --
Corporate, Other and Eliminations...................... 45,160 45,160
---------- ----------
Total................................................ $ 45,160 $ 45,160
========== ==========
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The Company also reassessed the useful lives and the classification of its
identifiable intangible assets and determined that they continue to be
appropriate. The components of the amortizable intangible assets consist of the
following (in thousands):
Weighted As of December 31, 2004 As of December 31, 2003
Average --------------------------- ---------------------------
Useful Life/ Carrying Accumulated Carrying Accumulated
Contract Life Amount(1) Amortization(1) Amount(1) Amortization(1)
------------- --------- --------------- --------- ---------------
Patents................................................. 5 $ 485 $ (417) $ 485 $ (320)
Power sales agreements.................................. 23 85,099 (43,115) 86,962 (40,180)
Fuel supply and fuel management contracts............... 23 5,000 (1,826) 22,198 (4,991)
Geothermal lease rights................................. 20 19,518 (550) 19,518 (450)
Other................................................... 15 4,755 (526) 2,088 (208)
--------- --------- --------- ---------
Total.................................................. $ 114,857 $ (46,434) $ 131,251 $ (46,149)
========= ========= ========= =========
- ------------
<FN>
(1) Fully amortized intangible assets are not included.
</FN>
Amortization expense of Other Intangible Assets was $4.6 million, $4.9
million and $21.1 million, in 2004, 2003 and 2002, respectively. Assuming no
future impairments of these assets or additions as the result of acquisitions,
annual amortization expense will be $3.9 million in 2005, $3.8 million in 2006,
$3.8 million in 2007, $3.8 million in 2008 and $3.5 million in 2009.
6. Acquisitions
The Company seeks to acquire power generating facilities that provide
significant potential for revenue, cash flow and earnings growth, and that
provide the opportunity to enhance the operating efficiency of its plants.
Acquisition activity is dependent on the availability of financing on attractive
terms and the expectation of returns that meets the Company's long-term
requirements. The following material mergers and acquisitions were consummated
during the years ended December 31, 2004 and 2003. There were no mergers or
acquisitions consummated during the year ended December 31, 2002. For all
business combinations, the results of operations of the acquired companies were
incorporated into the Company's Consolidated Financial Statements commencing on
the date of acquisition.
2004 Acquisitions
Calpine Cogeneration Company Transaction
On March 23, 2004, the Company completed the acquisition of the remaining
20% interest in Calpine Cogeneration Corporation ("Calpine Cogen"), which holds
interests in six power facilities, from NRG Energy, Inc. ("NRG") for
approximately $2.5 million. The Company purchased its initial 80% interest in
Calpine Cogen (formerly known as Cogeneration Corporation of America) from NRG
in 1999. Prior to the acquisition, the Company consolidated the assets of
Calpine Cogen in its financial statements and reflected the 20% interest held by
NRG as a minority interest. NRG's minority interest had a carrying value of
approximately $37.5 million at the time of acquisition. The carrying value of
the underlying assets was adjusted downward on a pro-rata basis for the
difference between the purchase price and the carrying value of NRG's minority
interest. As a result of the current transaction, the Company now has a 100%
interest in the Newark, Parlin, Morris and Pryor facilities, an 83% interest in
the Philadelphia Water Project, and a 50% interest in the Grays Ferry Power
Plant.
Aries Transaction
On March 26, 2004, the Company acquired the remaining 50% interest in the
Aries facility from a subsidiary of Aquila, Inc. (Aquila and its subsidiaries
referred to collectively as "Aquila"). At the same time, Aries terminated a
tolling contract with another subsidiary of Aquila. Aquila paid $5 million in
cash and assigned certain transmission and other rights to the Company. Aquila
and the Company also amended a master netting agreement between them, and as a
result, the Company returned cash margin deposits totaling $10.8 million to
Aquila. Contemporaneous with the closing of the acquisition, Aries' existing
construction loan was converted to two term loans totaling $178.8 million. The
Company contributed $15 million of equity to Aries in connection with the term
out of the construction loan.
-88-
The amounts below represents 50% of the fair value of the assets acquired
and liabilities assumed in the transaction. These amounts together with 50% of
the investment owned by the Company prior to the acquisition are now fully
consolidated into the Company's financial statements.
Current assets.................................................... $ 1,028
Contracts......................................................... 2,505
Property, plant and equipment..................................... 100,793
Other assets...................................................... 1,902
Current liabilities............................................... (1,978)
Derivative liability.............................................. (16,022)
Long-term debt.................................................... (88,228)
Brazos Valley Power Plant Transaction
On March 31, 2004, the Company closed on the purchase of the 570-megawatt,
natural gas-fired, Brazos Valley Power Plant ("Brazos Valley") in Fort Bend
County, Texas, for total consideration of approximately $181.1 million. The
Company used the net proceeds from the sale of its undivided interest in the
Lost Pines 1 facility (in January 2004) and cash on hand to acquire this
facility in a transaction structured as a tax deferred like-kind exchange under
IRS Section 1031. The consortium of banks that had provided construction
financing for the power plant and had taken possession of the plant from the
original developer in 2003 indirectly owned the special purpose companies that
owned Brazos Valley. Brazos Valley has become part of the collateral package for
the Calpine Construction Finance Company, L.P. ("CCFC I") First Priority Secured
Institutional Term Loans Due 2009 and Second Priority Senior Secured Floating
Rate Notes Due 2011. The fair value of the Brazos Valley facility was equal to
the purchase price and as a result, the entire purchase price was allocated to
the power plant assets and is recorded in property plant and equipment in the
Company's consolidated balance sheet.
2003 Acquisition
Thomassen Turbine Systems Transaction
On February 26, 2003, the Company, through its wholly-owned subsidiary
Calpine European Finance, LLC, purchased 100% of the outstanding stock of
Babcock Borsig Power Turbine Services ("BBPTS") from its parent company, Babcock
Borsig. Immediately following the acquisition, the BBPTS name was changed to
Thomassen Turbine Systems B.V. ("TTS"). The Company's total cost of the
acquisition was $12.0 million and was comprised of two pieces. The first was a
$7.0 million cash payment to Babcock Borsig to acquire the outstanding stock of
TTS. Included in this payment was the right to a note receivable valued at 11.9
million Euro (approximately US$12.9 million on the acquisition date) due from
TTS, which the Company acquired from Babcock Borsig for $1. Additionally, as of
the date of the acquisition, TTS owed $5.0 million in payments to another of the
Company's wholly owned subsidiaries, PSM, under a pre-existing license
agreement. Because of the acquisition, TTS ceased to exist as a third party
debtor to the Company, thereby resulting in a reduction of third party
receivables of $5.0 million from the Company's consolidated perspective.
Pro Forma Effects of Acquisitions
Acquired subsidiaries are consolidated upon closing date of the
acquisition. The table below reflects the Company's unaudited pro forma combined
results of operations for all business combinations during 2004 and 2003, as if
the acquisitions had taken place at the beginning of fiscal year 2002. The
Company's combined results include the effects of Calpine Cogen, Aries, Brazos
Valley and TTS (in thousands, except per share amounts):
2004 2003 2002
------------- ------------ ------------
Total revenue........................................................................ $ 8,805,694 $ 8,611,581 $ 7,166,724
Income (loss) before discontinued operations and cumulative effect of
accounting changes................................................................. $ (450,384) $ (41,380) $ 4,231
Net income (loss).................................................................... $ (250,176) $ 266,743 $ 120,458
Net income (loss) per basic share.................................................... $ (0.58) $ 0.68 $ 0.34
Net income (loss) per diluted share.................................................. $ (0.58) $ 0.67 $ 0.33
-89-
In management's opinion, these unaudited pro forma amounts are not
necessarily indicative of what the actual combined results of operations might
have been if the 2004 and 2003 acquisitions had been effective at the beginning
of fiscal year 2002. In addition, they are not intended to be a projection of
future results and do not reflect all the synergies that might be achieved from
combined operations.
7. Investments in Power Projects
The Company's investments in power projects are integral to its operations.
As discussed in Note 2, the Company's joint venture investments were evaluated
under FIN 46-R to determine which, if any, entities were VIEs. Based on this
evaluation, the Company determined that the Acadia Power Partners, LLC,
Valladolid III Energy Center, Grays Ferry Power Plant, Whitby Cogeneration
facility and the Androscoggin Energy Center were VIEs, in which the Company held
a significant variable interest. However, all of the entities except for Acadia
Power Partners, LLC met the definition of a business and qualified for the
business scope exception provided in paragraph 4(h) of FIN 46-R, and
consequently were not subject to the VIE consolidated model. Further, based on a
qualitative and quantitative assessment of the expected variability in Acadia
Power Partners, LLC, the Company was not the Primary Beneficiary. Consequently,
the Company continues to account for its joint venture investments in power
projects in accordance with APB Opinion No. 18, "The Equity Method of Accounting
For Investments in Common Stock" and FIN 35, "Criteria for Applying the Equity
Method of Accounting for Investments in Common Stock (An Interpretation of APB
Opinion No. 18)." However, in the fourth quarter of 2004, the Company changed
from the equity method to the cost method to account for its investment in
Androscoggin as discussed below.
Acadia Power Partners, LLC ("Acadia") is the owner of a 1,210-megawatt
electric wholesale generation facility located in Louisiana and is a joint
venture between the Company and Cleco Corporation. The Company's involvement in
this VIE began upon formation of the entity in March 2000. The Company's maximum
potential exposure to loss at December 31, 2004, is limited to the book value of
its investment of approximately $214.5 million.
Valladolid III Energy Center is the owner of a 525-megawatt, natural
gas-fired energy center currently under construction for Comision Federal de
Electricidad ("CFE") at Valladolid, Mexico in the Yucatan Peninsula. The
facility will deliver electricity to CFE under a 25-year power sales agreement.
The project is a joint venture between the Company, Mitsui & Co., Ltd.,
("Mitsui") and Chubu Electric ("Chubu"), both headquartered in Japan. The
Company owns 45% of the entity while Mitsui and Chubu each own 27.5%.
Construction began in May 2004 and the project is expected to achieve commercial
operation in the summer of 2006. The Company's maximum potential exposure to
loss at December 31, 2004, is limited to the book value of its investment of
approximately $77.4 million.
Grays Ferry Cogeneration Partnership ("Grays Ferry") is the owner of a
175-megawatt gas-fired cogeneration facility located in Pennsylvania and is a
joint venture between the Company and Trigen-Schuylkill Cogeneration, Inc. The
Company's involvement in this VIE began with its acquisition of the independent
power producer, Cogeneration Corporation of America, Inc. ("Cogen America"), now
called Calpine Cogen, in December 1999. The Grays Ferry joint venture project
was part of the portfolio of assets owned by Cogen America. The Company's
maximum potential exposure to loss at December 31, 2004, is limited to the book
value of its investment of approximately $48.6 million.
Whitby Cogeneration Limited Partnership ("Whitby") is the owner of a
50-megawatt gas-fired cogeneration facility located in Ontario, Canada and is a
joint venture between the Company and a privately held enterprise. The Company's
involvement in this VIE began with its acquisition of a portfolio of assets from
Westcoast Energy Inc. ("Westcoast") in September 2001, which included the Whitby
joint venture project. The Company's maximum potential exposure to loss at
December 31, 2004, is limited to the book value of its investment of
approximately $32.5 million.
Androscoggin Energy LLC ("AELLC") is the owner of a 136-megawatt gas-fired
cogeneration facility located in Maine and is a joint venture between the
Company, and affiliates of Wisvest Corporation and International Paper Company
("IP"). The Company's involvement in this VIE began with its acquisition of the
independent power producer, SkyGen Energy LLC ("SkyGen") in October 2000.
Androscoggin Energy LLC project was part of the portfolio of assets owned by
SkyGen. The facility had construction debt of $60.3 million and $60.8 million
outstanding as of December 31, 2004 and 2003, respectively. The debt is non-
recourse to Calpine Corporation. On November 3, 2004, a jury verdict was
rendered against AELLC in a breach of contract dispute with IP. See Note 25 for
more information about the legal proceeding. The Company recorded its $11.6
million share of the award amount in the third quarter of 2004. On November 26,
2004, AELLC filed a voluntary petition for relief under Chapter 11 of the
Bankruptcy Code. As a result of the bankruptcy, the Company has lost significant
influence and control of the project and has adopted the cost method of
accounting for its investment in Androscoggin. Also, in December 2004 the
-90-
Company determined that its investment, in Androscoggin including outstanding
notes receivable and O&M receivable, was impaired and recorded a $5.0 million
impairment reserve.
The following investments are accounted for under the equity method except
for Androscoggin Energy Center which is accounted for under the cost method (in
thousands):
Ownership Investment Balance at
Interest as of December 31,
December 31, -------------------------
2004 2004 2003
-------------- ----------- -----------
Acadia Energy Center(1)................................................................ 50.0% $ 214,501 $ 221,038
Valladolid III Energy Center........................................................... 45.0% 77,401 67,320
Grays Ferry Power Plant................................................................ 50.0% 48,558 53,272
Whitby Cogeneration(2)................................................................. 15.0% 32,528 31,033
Aries Power Plant(3)................................................................... 100.0% -- 58,205
Androscoggin Energy Center(4).......................................................... 32.3% -- 11,823
Other (5).............................................................................. -- 120 501
----------- ----------
Total investments in power projects.................................................. $ 373,108 $ 443,192
=========== ==========
- ------------
<FN>
(1) On May 12, 2003, the Company completed the restructuring of its interest in
Acadia. As part of the transaction, the partnership terminated its
580-megawatt, 20-year tolling arrangement with a subsidiary of Aquila, Inc.
in return for a cash payment of $105.5 million. Acadia recorded a gain of
$105.5 million and then made a $105.5 million distribution to Calpine.
Contemporaneously, the Company's wholly owned subsidiary, CES, entered into
a new 20-year, 580-megawatt tolling contract with Acadia. CES now markets
all of the output from the Acadia Power Project under the terms of this new
contract and an existing 20-year tolling agreement. Cleco receives a
priority cash distributions as its consideration for the restructuring.
Also, as a result of this transaction, the Company recorded, as its share
of the termination payment from the Aquila subsidiary, a $52.8 million gain
as of December 31, 2003, which was recorded within "Income from
unconsolidated investments in power projects and oil and gas properties" in
the Consolidated Statement of Operations. Due to the restructuring of its
interest in Acadia, the Company was required to reconsider its investment
in the entity under FIN 46 and determined that it is not the Primary
Beneficiary and accordingly will continue to account for its investment
using the equity method. See Note 2 for further information. See Note 25
for a legal proceeding involving Acadia Energy Center.
(2) Whitby is owned 50% by the Company but a 70% economic share in the
Company's ownership interest has been effectively transferred to Calpine
Power, LP ("CPLP") through a loan from CPLP to the Company's entity which
holds the investment interest in Whitby.
(3) On March 26, 2004, the Company acquired the remaining 50 percent interest
in Aries Power Plant. See Note 6 for a discussion of the acquisition.
(4) Excludes certain Notes Receivable (see Note 8).
(5) Other previously included Loto Energy, LLC ("Loto"). In the three months
ended, the company committed to a plan of divestiture of its remaining oil
and gas assets, which included Loto. In accordance with SFAS No. 144 the
Company's equity method investment in Loto of 19 percent was considered
part of this larger disposal group and therefore evaluated and accounted
for as a discontinued operation. Accordingly, the Company made
reclassifications to current and prior period financial statements to
reflect the designation as "held for sale" of the investment balance and to
separately classify the income from the unconsolidated investment from
operating results of continuing operations to discontinued operations in
the three months ended June 30, 2005. The tables below include Loto through
December 31, 2004, for distributions from investments and related party
transactions with unconsolidated investments in power projects and oil and
gas properties. See Note 10 for more information on the sale of the
Company's remaining domestic oil and gas exploration and production
properties and assets.
</FN>
On November 26, 2003, the Company completed the sale of its 50 percent
interest in the Gordonsville Power Plant. Under the terms of the transaction,
the Company received $36.2 million in cash for its $25.4 million investment and
recorded a pre-tax gain of $7.1 million. The remaining cash of $0.6 million is
to be distributed to the partners in late 2005.
-91-
On September 2, 2004, the Company completed the sale of its equity
investment in the Calpine Natural Gas Trust ("CNGT"). In accordance with SFAS
No. 144 the Company's 25 percent equity method investment in the CNGT was
considered part of the larger disposal group and therefore evaluated and
accounted for as a discontinued operation. Accordingly, the Company made
reclassifications to current and prior period financial statements to reflect
the sale or designation as "held for sale" of the CNGT investment balance and to
separately classify the income from the unconsolidated investment as well as the
gain on sale of the investment from operating results of continuing operations
to discontinued operations. The tables below for distributions from investments
and related party transactions with unconsolidated investments in power projects
and oil and gas properties include CNGT through the date of sale, September 2,
2004. See Note 10 for more information on the sale of the Canadian natural gas
reserves and petroleum assets.
The combined unaudited results of operations and financial position of the
Company's equity and cost method affiliates are summarized below (in thousands):
December 31,
------------------------------------------
2004 2003 2002
------------ ------------ ------------
Condensed statements of operations:
Revenue................................................................................ $ 237,983 $ 416,506 $ 372,212
Gross profit........................................................................... 45,994 147,247 151,784
Income from continuing operations before extraordinary items and cumulative effect
of a change in accounting principle................................................... (9,230) 174,730 70,596
Net income (loss)...................................................................... (9,230) 174,730 70,596
Condensed balance sheets:
Current assets......................................................................... $ 67,022 $ 86,811
Non-current assets..................................................................... 897,574 1,468,160
----------- ------------
Total assets........................................................................... $ 964,596 $ 1,554,971
=========== ============
Current liabilities.................................................................... $ 150,716 $ 90,933
Non-current liabilities................................................................ 114,597 727,807
----------- ------------
Total liabilities...................................................................... $ 265,313 $ 818,740
=========== ============
The debt on the books of the unconsolidated investments is not reflected on
the Company's balance sheet. At December 31, 2004 and 2003, investee debt was
approximately $133.9 million and $439.3 million, respectively. Of these amounts,
$63.4 million and $60.8 million, respectively, relates to the Company's
investment in AELLC, for which the cost method of accounting was used as of
December 31, 2004. Based on the Company's pro rata ownership share of each of
the investments, the Company's share would be approximately $46.6 million and
$140.8 million for the respective periods. These amounts include the Company's
share for AELLC of $20.5 million and $19.7 million, respectively. However, all
such debt is non-recourse to the Company.
-92-
The following details the Company's income and distributions from
investments in unconsolidated power projects (in thousands):
Income (loss) from
Unconsolidated Investments
in Power Projects Distributions
-------------------------------- ------------------------------
For the Years Ended December 31,
------------------------------------------------------------------
2004 2003 2002 2004 2003 2002
-------- -------- -------- -------- -------- --------
Acadia Power Partners, LLC .................. $ 14,142 $ 75,272 $ 14,590 $ 21,394 $136,977 $ 11,969
Valladolid III Energy Center ................ 76 -- -- -- -- --
Grays Ferry Power Plant ..................... (2,761) (1,380) (1,499) -- -- --
Whitby Cogeneration ......................... 1,433 303 411 1,499 -- --
Aries Power Plant ........................... (4,264) (3,442) (43) -- -- --
Calpine Natural Gas Trust ................... -- -- -- 6,127 1,959 --
Androscoggin Energy Center .................. (23,566) (7,478) (3,951) -- --
Gordonsville Power Plant .................... -- 11,985 5,763 -- 2,672 2,125
Lockport Power Plant ........................ -- -- 1,570 -- -- --
Other ....................................... 12 (1) (351) 849 19 23
-------- -------- -------- -------- -------- --------
Total ..................................... $(14,928) $ 75,259 $ 16,490 $ 29,869 $141,627 $ 14,117
======== ======== ======== ======== ======== ========
Interest income on loans to power projects(1) $ 840 $ 465 $ 62
-------- -------- --------
Total ..................................... $(14,088) $ 75,724 $ 16,552
======== ======== ========
- ------------
<FN>
The Company provides for deferred taxes to the extent that distributions exceed
earnings.
(1) At December 31, 2004 and 2003, loans to power projects represented an
outstanding loan to the Company's 32.3% owned investment, AELLC, in the
amounts of $4.0 million and $13.3 million, respectively, after impairment
charges and reserves.
</FN>
In the fourth quarter of 2002, income from unconsolidated investments in
power projects and oil and gas properties was reclassified out of total revenue
and is now presented as a component of other income from operations. Prior
periods have also been reclassified accordingly.
Related-Party Transactions with Unconsolidated Investments in Power
Projects
The Company and certain of its equity and cost method affiliates have
entered into various service agreements with respect to power projects.
Following is a general description of each of the various agreements:
Operation and Maintenance Agreements -- The Company operates and
maintains the Acadia and Androscoggin Energy Centers. This includes routine
maintenance, but not major maintenance, which is typically performed under
agreements with the equipment manufacturers. Responsibilities include
development of annual budgets and operating plans. Payments include
reimbursement of costs, including Calpine's internal personnel and other
costs, and annual fixed fees.
Construction Management Services Agreements -- The Company provides
construction management services to the Valladolid III Energy Center.
Payments include reimbursement of costs, including the Company's internal
personnel and other costs.
Administrative Services Agreements -- The Company handles
administrative matters such as bookkeeping for certain unconsolidated
investments. Payment is on a cost reimbursement basis, including Calpine's
internal costs, with no additional fee.
Power Marketing Agreements -- Under agreements with Androscoggin
Energy LLC, CES can either market the plant's power as the power facility's
agent or buy the power directly. Terms of any direct purchase are to be
agreed upon at the time and incorporated into a transaction confirmation.
Historically, CES has generally bought the power from the power facility
rather than acting as its agent.
Gas Supply Agreement -- CES can be directed to supply gas to the
Androscoggin Energy Center facility pursuant to transaction confirmations
between the facility and CES. Contract terms are reflected in individual
transaction confirmations.
-93-
The power marketing and gas supply contracts with CES are accounted for as
either purchase and sale arrangements or as tolling arrangements. In a purchase
and sale arrangement, title and risk of loss associated with the purchase of gas
is transferred from CES to the project at the gas delivery point. In a tolling
arrangement, title to fuel provided to the project does not transfer, and CES
pays the project a capacity and a variable fee based on the specific terms of
the power marketing and gas supply agreements. In addition to the contracts
specified above, CES maintains two tolling agreements with the Acadia facility
which are accounted for as leases. These tolling agreements expire in 2022. In
accordance with the terms of the contracts, CES supplies all necessary fuel to
generate the energy it takes and pays a capacity charge as well as an operations
and maintenance fee to Acadia. The Company reflects 100% of the lease expense
through CES, a consolidated subsidiary, and 50% of the lease revenue in equity
in earnings of an unconsolidated subsidiary. The total future minimum lease
payments for the tolling agreements are as follows (in thousands):
2005............................................................... $ 63,967
2006............................................................... 63,967
2007............................................................... 65,902
2008............................................................... 67,836
2009............................................................... 67,836
Thereafter......................................................... 847,952
-----------
Total............................................................ $ 1,177,460
===========
All of the other power marketing and gas supply contracts are accounted for
as purchases and sales.
The related party balances as of December 31, 2004 and 2003, reflected in
the accompanying consolidated balance sheets, and the related party transactions
for the years ended December 31, 2004, 2003 and 2002, reflected in the
accompanying consolidated statements of operations are summarized as follows (in
thousands):
2004 2003
--------- ----------
As of December 31,
Accounts receivable...................................... $ 765 $ 1,156
Accounts payable......................................... 9,489 12,172
Interest receivable...................................... -- 2,074
Note Receivable.......................................... 4,037 13,262
Other receivables........................................ -- 8,794
2004 2003 2002
---------- ---------- ----------
For the Years Ended December 31,
Revenue................................. $ 1,241 $ 3,493 $ 4,729
Cost of Revenue......................... 115,008 82,205 36,290
Interest income......................... 840 1,117 132
Gain on sale of assets.................. 6,240 62,176 --
8. Notes Receivable
Generally, notes receivable are recorded at the face amount, net of
allowances. These notes bear interest at rates that approximate current market
interest rates at the time of issuance. Certain long-term notes receivable have
no stated rate and are recorded by discounting expected future cash flows using
then current interest rates at which similar loans would be made to borrowers
with similar credit ratings and remaining maturities. The Company intends to
hold these notes to maturity. The amortization of the discount is recognized as
interest income, using the effective interest method, over the repayment term of
the notes. The Company reviews the financial condition of customers prior to
granting credit. The allowance represents the Company's best estimate of the
amount of probable credit losses in the Company's existing notes receivable. The
Company determines the allowance based on a variety of factors, including
economic trends and conditions and significant one-time events affecting the
note issuer, the length of time principal and interest payments are past due and
historical write off experience. Also, specific provisions are recorded for
individual notes receivables when the Company becomes aware of a customer's
inability to meet its financial obligations, such as in the case of bankruptcy
filings or deterioration in the customer's operating results or financial
position. The Company reviews the adequacy of its notes receivable allowance
quarterly. Generally, individual past due amounts are reviewed for
collectibility. Interest income is reserved when amounts are more than 90 days
past due or sooner if circumstances indicated that recoverability is not
reasonably assured. Past due amounts are charged off against the allowance after
all means of collection have been exhausted and the potential for recovery is
considered remote.
-94-
As of December 31, 2004, and 2003, the components of notes receivable were
(in thousands):
2004 2003
------------ -----------
PG&E (Gilroy) note............................... $ 145,853 $ 155,901
Panda note....................................... 38,644 38,644
Eastman note..................................... 19,748 --
Androscoggin note................................ 4,037 13,262
Mitsui & Co., Ltd note........................... -- 8,779
Other............................................ 7,168 8,506
----------- -----------
Total notes receivable......................... 215,450 225,092
Less: Notes receivable, current portion
included in other current assets........... (11,770) (11,463)
----------- -----------
Notes receivable, net of current portion......... $ 203,680 $ 213,629
=========== ===========
Gilroy Note
Calpine Gilroy Cogen, L.P. ("Gilroy") had a long-term 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 ("CPUC") approved the restructuring of the PPA between Gilroy and
PG&E. Under the terms of the restructuring, PG&E and Gilroy were 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 had earned 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 had issued notes to the Company. These notes are
scheduled to be paid by PG&E during the period from February 2003 to September
2014. The first scheduled note repayment of $1.7 million was received in
February 2003.
On December 4, 2003, the Company announced that it had sold to a group of
institutional investors its right to receive payments from PG&E under the
Agreement between PG&E and Gilroy, a California Limited Partnership (PG&E Log
No. 08C002) For Termination and Buy-Out of Standard Offer 4 Power Purchase
Agreement, executed by PG&E on July 1, 1999 (the "Gilroy Receivable") for $133.4
million in cash. Because the transaction did not satisfy the criteria for sales
treatment under SFAS No. 140 it was reflected in the Consolidated Financial
Statements as a secured financing, with a note payable of $133.4 million. The
receivable balance and note payable balance are both reduced as PG&E makes
payments to the buyer of the Gilroy Note. The $24.1 million difference between
the $157.5 million book value of the Gilroy Note at the transaction date and the
cash received is recognized as additional interest expense over the repayment
term. The Company will continue to record interest income over the repayment
term and interest expense will be accreted on the amortizing note payable
balance.
Pursuant to the applicable transaction agreements, each of Gilroy and
Calpine Gilroy 1, Inc., the general partner of Gilroy, has been established as
an entity with its existence separate from the Company and other subsidiaries of
the Company. The Company consolidates these entities.
Panda Note
In June 2000, the Company entered into a series of turbine sale contracts
with, and acquired the development rights to construct, own and operate the
Oneta Energy Center ("Oneta") from Panda Energy International, Inc. and certain
related entities. As part of the transaction, the Company extended PLC II, LLC
("PLC") a loan bearing an interest rate of LIBOR plus 5%. The loan is
collateralized by PLC's carried interest in the income generated from Oneta,
which achieved full commercial operations in June 2003. Additionally, Panda
Energy International, Inc. executed a parental Guaranty as to the loan.
On November 5, 2003, Panda Energy International, Inc. and certain related
parties, including PLC, (collectively "Panda") filed suit against the Company
and certain of its affiliates alleging, among other things, that the Company
breached duties of care and loyalty allegedly owed to Panda by failing to
correctly construct and operate Oneta in accordance with Panda's original plans.
Panda alleges that it is entitled to a portion of the profits from Oneta and
that the Company's actions have reduced the profits from Oneta, thereby
undermining Panda's ability to repay monies owed to the Company under the loan.
The Company has filed a counterclaim against PLC based on a guaranty and a
motion to dismiss as to the causes of action alleging federal and state
securities laws violations. The court recently granted the Company's motion to
dismiss, but allowed Panda an opportunity to re-plead. The Company considers
Panda's lawsuit to be without merit and intends to defend vigorously against it.
Discovery is currently in progress.
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Panda defaulted on the loan, which was due on December 1, 2003. Because of
the Guaranty and the collateral, the Company determined that a reserve was not
needed as of December 31, 2004. However, the Company ceased accruing interest
after the default date and continues to closely monitor the receivable pending
the resolution of the litigation. See Note 25 for more information on the
litigation.
Eastman Note
In August 2000, the Company entered into an Energy Services Agreement
("ESA") with Eastman Chemical Company ("Eastman") at its Columbia facility in
South Carolina. As part of the agreement, the Company financed the construction
of the Heat Thermal Medium Heater System ("HTM") facilities. Under this
agreement, Eastman will repay the Company $20.0 million for the HTM financed
facilities over a period of 20 years with an annual interest rate of 9.76%. The
first note receivable payment was received in April 2004.
Androscoggin Note
The Company has a note receivable from its unconsolidated cost method
investee AELLC. The Company ceased accruing interest income on its note
receivable related to unreimbursed administration costs associated with the
Company's management of the project after a jury verdict was rendered against
AELLC in a breach of contract dispute. In December 2004, the Company determined
that its investment in Androscoggin was impaired and recorded a $5.0 million
impairment reserve. On December 31, 2004, the carrying value after reserves of
the Company's notes receivable balance due from AELLC was $4.0 million. See Note
7 for further information.
Mitsui Note
In December 2003, the Company contributed two gas turbines with a book
value of approximately $76.0 million in exchange for a 45% interest in the
Valladolid Joint Venture project with Mitsui in Mexico. The Company recorded its
interest in the project at a value of $67.0 million, which reflected the cost of
the turbines less a $9.0 million note receivable that was booked upon transfer
of the turbines, representing a return of capital. Subsequently, Mitsui assumed
the note receivable from the project and received additional equity in the
project. At the time of the original investment, the Company's investment in and
notes receivable from Mitsui exceeded its share of its underlying equity by $31
million, which will be amortized as an adjustment to the Company's share of the
project's net income over the depreciable life of the underlying assets. In
October 2004, the note receivable matured and all payments were received.
9. Canadian Power and Gas Trusts
Calpine Power Income Fund -- On August 29, 2002, the Company announced it
had completed a Cdn$230 million (US$147.5 million) initial public offering of
its Canadian income fund -- Calpine Power Income Fund ("CPIF"). The 23 million
Trust Units issued to the public were priced at Cdn$10 per unit, to initially
yield 9.35% per annum. On September 20, 2002, the syndicate of underwriters
fully exercised the over-allotment option that it was granted as part of the
initial public offering of Trust Units and acquired 3,450,000 additional Trust
Units of CPIF at Cdn$10 per Trust Unit, generating Cdn$34.5 million (US$21.9
million). CPIF used the proceeds of the initial offering and over-allotment to
purchase an equity interest in CPLP, which holds two of Calpine's Canadian power
generating assets, the Island Cogeneration Facility and the Calgary Energy
Centre. CPIF also used the proceeds to make a loan to a Calpine subsidiary which
owns Calpine's other Canadian power generating asset, the equity investment in
the Whitby cogeneration plant. Combined, these assets represent approximately
168.3 net megawatts of power generating capacity.
On February 13, 2003, the Company completed a secondary offering of
17,034,234 Warranted Units of CPIF for gross proceeds of Cdn$153.3 million
(US$100.9 million). The Warranted Units were sold to a syndicate of underwriters
at a price of Cdn$9.00. Each Warranted Unit consisted of one Trust Unit and one-
half of one Trust Unit purchase warrant. Each Warrant entitled the holder to
purchase one Trust Unit at a price of Cdn$9.00 per Trust Unit at any time on or
prior to December 30, 2003, after which time the Warrant became null and void.
During 2003 a total of 8,508,517 Warrants were exercised, resulting in cash
proceeds to the Company of Cdn$76.6 million (US$56.7 million). CPIF used the
proceeds from the secondary offering and Warrant exercise to purchase an
additional equity interest in CPLP.
The Company currently holds less than 1% of CPIF's trust units; however,
the Company retains a 30% subordinated equity interest in CPLP and has a
significant continuing involvement in the assets transferred to CPLP. The assets
of CPLP are included in the Company's consolidated balance sheet under the
guidance of SFAS No. 66, "Accounting for Sales of Real Estate" due to the
Company's significant continuing involvement in the assets transferred to CPLP.
Therefore, the financial results of CPLP are consolidated in the Company's
financial statements. The proceeds from the initial public offering, the
exercise of the underwriters over-allotment, the proceeds from the secondary
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offering of Trust Units and the proceeds from the exercise of Warrants represent
the Fund's 70% equity interest in CPLP and its underlying generating assets and
have been recorded as minority interests in the Company's consolidated balance
sheet. Because of this equity ownership in CPLP, the Company considers CPIF a
related party. See Note 13 for a discussion of the capital lease transaction
with CPIF.
Calpine Natural Gas Trust -- On October 15, 2003, the Company closed the
initial public offering of CNGT. A total of 18,454,200 trust units were issued
at a price of Cdn$10.00 per trust unit for gross proceeds of approximately
Cdn$184.5 million (US$139.4 million). CNGT acquired select natural gas and
petroleum properties from Calpine with the proceeds from the initial public
offering, Cdn$61.5 million (US$46.5 million) proceeds from a concurrent issuance
of units to a Canadian affiliate of Calpine, and Cdn$40.0 million (US$30.2
million) proceeds from bank debt. Net proceeds to Calpine, totaled approximately
Cdn$207.9 million (US$157.1 million), reflecting a gain of $62.2 million on the
sale of the properties. On October 22, 2003, the syndicate of underwriters fully
exercised the over-allotment option associated with the initial public offering
resulting in additional cash to the CNGT. As a result of the exercise of the
over-allotment option, Calpine acquired an additional 615,140 trust units at
Cdn$10.0 per trust unit for a cash payment to the CNGT of Cdn$6.2 million
(US$4.7 million). Prior to the subsequent sale of this investment, the Company
held 25 percent of the outstanding trust units of CNGT and accounted for it
using the equity method.
On September 2, 2004, the Company completed the sale of its equity
investment in the CNGT. In accordance with SFAS No. 144 the Company's 25 percent
equity method investment in the CNGT was considered part of the larger disposal
group and therefore evaluated and accounted for as a discontinued operation. See
Note 10 for more information on the sale of the Canadian natural gas reserves
and petroleum assets. In addition, the Company considered CNGT a related party
and disclosed all transactions up through the date of sale as such. See Note 7
for more information on related party transactions with unconsolidated
investments.
10. Discontinued Operations
The Company has adopted a strategy of conserving its core strategic assets
and selectively disposing of certain less strategically important assets, which
serves primarily to raise cash for general corporate purposes and strengthen the
Company's balance sheet through repayment of debt. Set forth below are the
Company's material asset disposals by reportable segment that impacted the
Company's Consolidated Financial Statements as of December 31, 2004, 2003 and
2002:
Corporate and Other
On July 31, 2003, the Company completed the sale of its specialty data
center engineering business and recorded a pre-tax loss on the sale of $11.6
million.
Oil and Gas Production and Marketing
On August 29, 2002, the Company completed the sale of certain non-strategic
oil and gas properties ("Medicine River properties") located in central Alberta
to NAL Oil and Gas Trust and another institutional investor for Cdn$125.0
million (US$80.1 million). As a result of the sale, the Company recorded a
pre-tax gain of $21.9 million in the third quarter 2002.
On October 1, 2002, the Company completed the sale of substantially all of
its British Columbia oil and gas properties to Calgary, Alberta-based Pengrowth
Corporation for gross proceeds of approximately Cdn$387.5 million (US$244.3
million). Of the total consideration, the Company received US$155.9 million in
cash. The remaining US$88.4 million of consideration was paid by Pengrowth
Corporation's purchase in the open market of US$203.2 million in aggregate
principal amount of the Company's debt securities. As a result of the
transaction, the Company recorded a US$37.4 million pre-tax gain on the sale of
the properties and a gain on the extinguishment of debt of US$114.8 million in
the fourth quarter 2002. The Company used approximately US$50.4 million of cash
proceeds to repay amounts outstanding under its US$1.0 billion term loan.
On October 31, 2002, the Company sold all of its oil and gas properties in
Drake Bay Field located in Plaquemines Parish, Louisiana for approximately $3
million to Goldking Energy Corporation. As a result of the sale, the Company
recognized a pre-tax loss of $0.02 million in the fourth quarter 2002.
On November 20, 2003, the Company completed the sale of its Alvin South
Field oil and gas assets located near Alvin, Texas for approximately $0.06
million to Cornerstone Energy, Inc. As a result of the sale, the Company
recognized a pre-tax loss of $0.2 million.
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On September 1, 2004, the Company along with Calpine Natural Gas L.P., a
Delaware limited partnership, completed the sale of its Rocky Mountain gas
reserves that were primarily concentrated in two geographic areas: the Colorado
Piceance Basin and the New Mexico San Juan Basin. Together, these assets
represented approximately 120 billion cubic feet equivalent ("Bcfe") of proved
gas reserves, producing approximately 16.3 million net cubic feet equivalent
("Mmcfe") per day of gas. Under the terms of the agreement Calpine received net
cash payments of approximately $218.7 million, and recorded a pre-tax gain of
approximately $103.7 million.
On September 2, 2004, the Company completed the sale of its Canadian
natural gas reserves and petroleum assets. These Canadian assets represented
approximately 221 Bcfe of proved reserves, producing approximately 61 Mmcfe per
day. Included in this sale was the Company's 25% interest in approximately 80
Bcfe of proved reserves (net of royalties) and 32 Mmcfe per day of production
owned by the CNGT. In accordance with SFAS No. 144 the Company's 25% equity
method investment in the CNGT was considered part of the larger disposal group
(i.e., assets to be disposed of together as a group in a single transaction to
the same buyer), and therefore evaluated and accounted for as discontinued
operations. Under the terms of the agreement, Calpine received cash payments of
approximately Cdn$808.1 million, or approximately US$626.4 million. Calpine
recorded a pre-tax gain of approximately $104.5 million on the sale of these
Canadian assets net of $20.1 million in foreign exchange losses recorded in
connection with the settlement of forward contracts entered into to preserve the
US dollar value of the Canadian proceeds.
In connection with the sale of its Canadian natural gas reserves and
petroleum assets, the Company entered into a seven-year gas purchase agreement
beginning on March 31, 2005, and expiring on October 31, 2011, that allows, but
does not require, the Company to purchase gas from the buyer at current market
index prices. The agreement is not asset specific and can be settled by any
production that the buyer has available.
In connection with the sale of the Rocky Mountain gas reserves, the New
Mexico San Juan Basin sales agreement allows for the buyer and the Company to
execute a ten-year gas purchase agreement for 100% of the underlying gas
production of sold reserves, at market index prices. Any agreement would be
subject to mutually agreeable collateral requirements and other customary terms
and provisions. As of October 1, 2004, the gas purchase agreement was finalized
and executed between the Company and the buyer.
The Company believes that all final terms of the gas purchase agreements
described above, are on a market value and arm's length basis. If the Company
elects in the future to exercise a call option over production from the disposed
components, the Company will consider the call obligation to have been met as if
the actual production delivered to the Company under the call was from assets
other than those constituting the disposed components.
In the three months ended June 30, 2005, the Company committed to a plan to
divest its remaining oil and gas assets. On July 7, 2005, the Company completed
the sale of substantially all of its remaining oil and gas assets to Rosetta
Resources Inc. ("Rosetta") for $1.05 billion, less approximately $60 million of
estimated transaction fees and expenses. Approximately $75 million of the
purchase price was withheld pending the transfer of certain properties for which
consents had not yet been obtained at the closing date. These financial
statements have been amended throughout to reflect the oil and gas assets and
related operations as discontinued operations.
In connection with the sale of the oil and gas assets to Rosetta, the
Company entered into a two-year gas purchase agreement expiring on December 31,
2009, for 100% of the production of the Sacramento basin assets, which represent
approximately 44% of the reserve assets sold to Rosetta. The Company will pay
the prevailing current market index price for all amounts acquired under the
agreement. The Company believes the gas purchase agreement was negotiated on an
arm's length basis and represents fair value for the production. Therefore, the
agreement does not provide the Company with significant influence over the
buyer's ability to realize the economic risks and rewards of owning the assets.
The following summary disclosures are made in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 69, "Disclosures About Oil and Gas
Producing Activities (An Amendment of FASB Statements 19, 25, 33 and 39)" ("SFAS
No. 69"). This data is a summary of the information, which prior to the
Company's commitment to a plan of divesture of its remaining oil and gas assets,
had been previously provided as Supplemental Information in the Company's 2004
Annual Report on Form 10-K. Users of this information should be aware that the
process of estimating quantities of proved, proved developed and proved
undeveloped crude oil and natural gas reserves is very complex, requiring
significant subjective decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a given reservoir
may also change substantially over time as a result of numerous factors
including, but not limited to, additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. Consequently, material revisions to reserve
estimates occur from
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time to time. Although every reasonable effort is made to ensure that reserve
estimates reported represent the most accurate assessments possible, the
significance of the subjective decisions required and variances in available
data for various reservoirs make these estimates generally less precise than
other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas and crude oil
that geological and engineering data demonstrate, with reasonable certainty, to
be recoverable in future years from known reservoirs under economic and
operating conditions existing at the time the estimates were made. Estimates of
proved reserves as of December 31, 2004, 2003 and 2002, were based on estimates
made by Netherland, Sewell & Associates Inc. ("NSA") for reserves in the United
States and by Gilbert Laustsen Jung Associates Ltd. ("GLJ") for 2003 and 2002
reserves in Canada, both independent petroleum reservoir engineers.
Net Proved Reserve Summary - Unaudited
The following table sets forth the Company's net proved reserves at
December 31 for each of the three years in the period ended December 31, 2004,
as estimated by the independent petroleum consultants.
During 2004, the Company revised downward its estimate of continuing proved
reserves by a total of approximately 58 Bcfe or 12%. Approximately 69% of the
total revision was attributable to the downward revision of the Company's
estimate of proved reserves in the Company's South Texas fields. The downward
revisions of the Company's estimates were due to information received from
production results and drilling activity that occurred during 2004. As a result
of the decreases in proved reserves, a non-cash impairment charge of
approximately $202.1 million was recorded for the year ended December 31, 2004,
which has been reclassified to discontinued operations. For the years ended
December 31, 2003 and 2002, the impairment charge reclassified to discontinued
operations was $2.9 million and $3.4 million, respectively. The following data
relates to the Company's oil and gas assets which have been reclassified to
held-for-sale in the corresponding balance sheets as of the dates indicated.
Unaudited
---------
(Bcfe)(1) equivalents(4):
Net proved reserves at December 31, 2002........................... 978
Net proved reserves at December 31, 2003........................... 821
Net proved reserves at December 31, 2004........................... 389
Net proved developed reserves:
Natural gas (Bcf)(1)
December 31, 2002................................................. 640
December 31, 2003................................................. 545
December 31, 2004................................................. 256
Natural gas liquids and crude oil (MBbl)(2)(3)
December 31, 2002................................................. 14,132
December 31, 2003................................................. 8,690
December 31, 2004................................................. 1,402
Bcf(1) equivalents(4)
December 31, 2002................................................. 725
December 31, 2003................................................. 596
December 31, 2004................................................. 264
- --------------
(1) Billion cubic feet or billion cubic feet equivalent, as applicable.
(2) Thousand barrels.
(3) Includes crude oil, condensate and natural gas liquids.
(4) Natural gas liquids and crude oil volumes have been converted to equivalent
gas volumes using a conversion factor of six cubic feet of gas to one
barrel of natural gas liquids and crude oil.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves - Unaudited
The following information has been developed utilizing procedures
prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and
production volumes estimated by the independent petroleum reservoir engineers.
This information may be useful for certain comparison purposes but should not be
solely relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as
representative of realistic assessments of future cash flows, nor should the
standardized measure of discounted future net cash flows be viewed as
representative of the value of the Company's oil and gas assets, which are
classified as held-for-sale in the Company's balance sheet as of the dates
indicated.The discounted future net cash flows presented below are based on
sales prices, cost rates and statutory income tax rates in existence as of the
date of the projections. Estimates of natural gas and crude oil reserves may be
revised in the future, development and production of the reserves may occur in
periods other than those assumed, and actual prices realized and costs incurred
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may vary significantly from those used. Income tax expense has been computed
using expected future tax rates and giving effect to tax deductions and credits
available, under current laws, and which relate to oil and gas producing
activities. Management does not rely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as proved reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
Unaudited
---------
December 31, 2004:
Standardized measure of discounted future net cash flows
relating to proved gas, natural gas liquids
and crude oil reserves............................................ $ 653
========
December 31, 2003:
Standardized measure of discounted future net cash flows
relating to proved gas, natural gas liquids
and crude oil reserves............................................ $ 1,341
========
December 31, 2002:
Standardized measure of discounted future net cash flows
relating to proved gas, natural gas liquids
and crude oil reserves............................................ $ 1,259
========
Electric Generation and Marketing
On December 16, 2002, the Company completed the sale of the 180-megawatt
DePere Energy Center in DePere, Wisconsin. The facility was sold to Wisconsin
Public Service for $120.4 million, which included $72.0 million in cash at
closing and a $48.4 million payment due in December 2003. As a result of the
sale, the Company recognized a pre-tax gain of $35.8 million. On December 17,
2002, the Company sold its right to the December 2003 payment to a third party
for $46.3 million, and recognized a pre-tax loss of $2.1 million thereon.
On January 15, 2004, the Company completed the sale of its 50-percent
undivided interest in the 545-megawatt Lost Pines 1 Power Project to GenTex
Power Corporation, an affiliate of the Lower Colorado River Authority ("LCRA").
Under the terms of the agreement, Calpine received a cash payment of $148.6
million and recorded a pre-tax gain of $35.3 million. In addition, CES entered
into a tolling agreement with LCRA providing for the option to purchase 250
megawatts of electricity through December 31, 2004. At December 31, 2003, the
Company's undivided interest in the Lost Pines facility was classified as "held
for sale" and subsequently sold in 2004.
In the three months ended June 30, 2005, the Company committed to a plan to
sell the Saltend Energy Centre, a 1,200-MW power plant in Hull, England, and on
July 28, 2005, the Company completed the sale to a company indirectly owned by
International Power, PLC and Mitsui & Co. Ltd., for a total sale price of
approximately 490 million British pounds, or approximately $848 million, plus
adjustments for working capital of $14.5 million, resulting in total gross
proceeds of $862.5 million. These financial statements have been amended
throughout to reflect the Saltend Energy Centre as a discontinued operation.
Summary
The Company made reclassifications to current and prior period financial
statements to reflect the sale of these oil and gas and power plant assets and
liabilities and to separately reclassify the operating results of the assets
sold and the gain (loss) on sale of those assets from the operating results of
continuing operations to discontinued operations.
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The tables below present the assets and liabilities held for sale by
segment as of December 31, 2004 and 2003, respectively (in thousands).
December 31, 2004
-----------------------------------------------
Electric Oil and Gas
Generation Production
and Marketing and Marketing Total
------------- ------------- ------------
Assets
Cash and cash equivalents .............................................. $ 65,405 $ -- $ 65,405
Accounts receivable, net ............................................... 49,147 -- 49,147
Inventories ............................................................. 5,088 -- 5,088
Prepaid expenses ........................................................ 14,307 -- 14,307
------------- ------------- ------------
Total current assets held for sale .................................... 133,947 -- 133,947
------------- ------------- ------------
Property, plant and equipment ........................................... 1,090,454 606,520 1,696,974
Other assets ............................................................ 20,826 924 21,750
------------- ------------- ------------
Total long-term assets held for sale ................................. $ 1,111,280 $ 607,444 $ 1,718,724
============= ============= ============
Liabilities
Accounts payable ........................................................ $ 31,342 $ -- $ 31,342
Current derivative liabilities .......................................... 8,935 -- 8,935
Other current liabilities ............................................... 30,925 1,265 32,190
------------- ------------- ------------
Total current liabilities held for sale ............................... 71,202 1,265 72,467
------------- ------------- ------------
Deferred income taxes, net of current portion ........................... 135,985 -- 135,985
Long-term derivative liabilities ........................................ 10,367 -- 10,367
Other liabilities ....................................................... 18,693 8,384 27,077
------------- ------------- ------------
Total long-term liabilities held for sale ............................ $ 165,045 $ 8,384 $ 173,429
============= ============= ============
December 31, 2003
-----------------------------------------------
Electric Oil and Gas
Generation Production
and Marketing and Marketing Total
------------- ------------- ------------
Assets
Cash and cash equivalents................................................ $ 29,698 $ -- $ 29,698
Accounts receivable, net................................................. 40,855 -- 40,855
Inventories.............................................................. 5,190 1,913 7,103
Current derivative assets 2,055 -- 2,055
Prepaid expenses......................................................... 11,059 -- 11,059
------------- ------------- ------------
Total current assets held for sale..................................... 88,857 1,913 90,770
------------- ------------- ------------
Property, plant and equipment............................................ 1,150,916 1,432,792 2,583,708
Other assets............................................................. 5,106 29,557 34,663
------------- ------------- ------------
Total long-term assets held for sale.................................. $ 1,156,022 $ 1,462,349 $ 2,618,371
============= ============= ============
Liabilities
Accounts payable......................................................... $ 27,103 $ -- $ 27,103
Other current liabilities................................................ 4,888 1,571 6,459
------------- ------------- ------------
Total current liabilities held for sale................................ 31,991 1,571 33,562
------------- ------------- ------------
Deferred income taxes, net of current portion............................ 103,517 -- 103,517
Long-term derivative liabilities......................................... 6,130 -- 6,130
Other liabilities........................................................ 19,009 25,652 44,661
------------- ------------- ------------
Total long-term liabilities held for sale............................. $ 128,656 $ 25,652 $ 154,308
============= ============= ============
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The tables below present significant components of the Company's income from
discontinued operations for 2004, 2003 and 2002, respectively (in thousands):
2004
---------------------------------------------------
Electric Oil and Gas
Generation Production Corporate
and Marketing and Marketing and Other Total
------------- ------------- --------- --------
Total revenue ............................................................. $ 392,705 $ 91,421 $ -- $484,126
============= ============= ========= ========
Gain on disposal before taxes ............................................. $ 35,327 $ 208,172 $ -- $243,499
Operating income (loss) from discontinued operations before taxes ......... 76,968 (99,023) -- (22,055)
------------- ------------- --------- --------
Income from discontinued operations before taxes .......................... $ 112,295 $ 109,149 $ -- $221,444
Income tax (provision) benefit ............................................ $ (26,442) $ 5,206 $ -- $(21,236)
------------- ------------- --------- --------
Income from discontinued operations, net of tax ........................... $ 85,853 $ 114,355 $ -- $200,208
============= ============= ========= ========
2003
---------------------------------------------------
Electric Oil and Gas
Generation Production Corporate
and Marketing and Marketing and Other Total
------------- ------------- --------- --------
Total revenue.............................................................. $ 363,046 $ 106,412 $ 3,748 $473,206
============= ============= ========= ========
Loss on disposal before taxes.............................................. $ -- $ (235) $ (11,571) $(11,806)
Operating income (loss) from discontinued operations before taxes.......... 4,045 170,326 (6,918) 167,453
------------- ------------- --------- --------
Income (loss) from discontinued operations before taxes.................... $ 4,045 $ 170,091 $ (18,489) $155,647
Income tax (provision) benefit............................................. 11,005 (46,498) 7,026 (28,467)
------------- ------------- --------- --------
Income from discontinued operations, net of tax............................ $ 15,050 $ 123,593 $ (11,463) $127,180
============= ============= ========= ========
2002
---------------------------------------------------
Electric Oil and Gas
Generation Production Corporate
and Marketing and Marketing and Other Total
------------- ------------- --------- --------
Total revenue.............................................................. $ 280,888 $ 170,259 $ 7,653 $458,800
============= ============= ========= ========
Gain on disposal before taxes.............................................. $ 35,840 $ 59,288 $ -- $ 95,128
Operating income (loss) from discontinued operations before taxes.......... (27,597) 71,721 (16,968) 27,156
------------- ------------- --------- --------
Income (loss) from discontinued operations before taxes.................... $ 8,243 $ 131,009 $ (16,968) $122,284
Income tax (provision) benefit............................................. 14,504 (27,009) 6,448 (6,057)
------------- ------------- --------- --------
Income from discontinued operations, net of tax............................ $ 22,747 $ 104,000 $ (10,520) $116,227
============= ============= ========= ========
The Company allocates interest to discontinued operations in accordance
with EITF Issue No. 87-24, "Allocation of Interest to Discontinued Operations."
The Company includes interest expense on debt which is required to be repaid as
a result of a disposal transaction in discontinued operations. Additionally,
other interest expense that cannot be attributed to other operations of the
Company is allocated based on the ratio of net assets to be sold less debt that
is required to be paid as a result of the disposal transaction to the sum of
total net assets of the Company plus consolidated debt of the Company, excluding
(a) debt of the discontinued operation that will be assumed by the buyer, (b)
debt that is required to be paid as a result of the disposal transaction and (c)
debt that can be directly attributed to other operations of the Company.
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Interest Expense Allocation 2004 2003 2002
----------- ----------- -----------
Electric generation and marketing
Saltend Energy Centre............. $ 14,613 $ 7,203 $ 5,170
----------- ----------- -----------
Total.......................... $ 14,613 $ 7,203 $ 5,170
=========== =========== ===========
Oil and gas production and marketing
Canadian and Rockies.............. $ 17,893 $ 19,797 $ 11,014
Remaining oil and gas assets...... 12,435 7,331 3,527
----------- ----------- -----------
Total.......................... $ 30,328 $ 27,128 $ 14,541
=========== =========== ===========
11. Debt
The annual principal repayments or maturities of the Company's debt
obligations as of December 31, 2004, are as follows (in thousands):
2005............................................................ $ 1,033,956
2006............................................................ 944,046
2007............................................................ 1,851,022
2008............................................................ 2,221,435
2009............................................................ 1,667,272
Thereafter...................................................... 10,257,034
--------------
Total......................................................... $ 17,974,765
==============
Covenant Restrictions -- The covenants in certain of the Company's debt
agreements currently impose the following restrictions on its activities:
o Certain of the Company's indentures place conditions on its ability to
issue indebtedness if the Company's interest coverage ratio (as
defined in those indentures) is below 2:1. Currently, the Company's
interest coverage ratio (as so defined) is below 2:1 and,
consequently, the Company generally would not be allowed to issue new
debt, except for (i) certain types of new indebtedness that refinances
or replaces existing indebtedness, and (ii) non-recourse debt and
preferred equity interests issued by the Company's subsidiaries for
purposes of financing certain types of capital expenditures, including
plant development, construction and acquisition expenses. In addition,
if and so long as the Company's interest coverage ratio is below 2:1,
the Company's ability to invest in unrestricted subsidiaries and
non-subsidiary affiliates and make certain other types of restricted
payments will be limited. As of December 31, 2004, the Company's
interest coverage ratio (as so defined) has fallen below 1.75:1 and,
until the ratio is greater than 1.75:1, certain of the Company's
indentures will prohibit any further investments in non-subsidiary
affiliates.
o Certain of the Company's indebtedness issued in the last half of 2004
was permitted under the Company's indentures on the basis that the
proceeds would be used to repurchase or redeem existing indebtedness.
While the Company completed a portion of such repurchases during the
fourth quarter of 2004 and the first quarter of 2005, the Company is
still in the process of completing the required amount of repurchases.
While the amount of indebtedness that must still be repurchased will
ultimately depend on the market price of the Company's outstanding
indebtedness at the time the indebtedness is repurchased, based on
current market conditions, the Company currently anticipates that it
will spend up to approximately $202.9 million on additional
repurchases in order to fully satisfy this requirement. The Company's
bond purchase requirement was estimated to be approximately $270
million as of December 31, 2004, and this amount has been classified
as Senior Notes, current portion on the Company's consolidated balance
sheet.
o When the Company or one of its subsidiaries sells a significant asset
or issues preferred equity, the Company's indentures generally require
that the net proceeds of the transaction be used to make capital
expenditures or to repurchase or repay certain types of subsidiary
indebtedness, in each case within 365 days of the closing date of the
transaction. In light of this requirement, and taking into account the
amount of capital expenditures currently budgeted for 2005, the
Company anticipates that it will need to use approximately $250.0 of
the net proceeds of the $360.0 million Two-Year Redeemable Preferred
Shares issued on October 26, 2004, and approximately $200.0 million of
the net proceeds of the $260.0 million Redeemable Preferred Shares
issued on January 31, 2005, to repurchase or repay certain subsidiary
indebtedness. The $250.0 million of long-term debt has been
reclassified as Senior Notes, current portion liability on the
Company's consolidated balance sheet. The actual amount of the net
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proceeds that will be required to be used to repurchase or repay
subsidiary debt will depend upon the actual amount of the net proceeds
that is used to make capital expenditures, which may be more or less
than the amount currently budgeted.
Deferred Financing Costs -- The deferred financing costs related to the
Company's Senior Notes and the Convertible Senior Notes are amortized over the
life of the related debt, ranging from 4 to 20 years, using the effective
interest rate method. Costs incurred in connection with obtaining other
financing are deferred and amortized over the life of the related debt. However,
when timing of debt transactions involve contemporaneous exchanges of cash
between the Company and the same creditor(s) in connection with the issuance of
a new debt obligation and satisfaction of an existing debt obligation, deferred
financing costs are accounted for in accordance with EITF Issue No. 96-19,
"Debtor's Accounting for a Modification or Exchange of Debt Instruments" ("EITF
Issue No. 96-19"). Depending on whether the transaction qualifies as an
extinguishment or modification, EITF Issue No. 96-19 requires the Company to
either write-off the original deferred financing costs and capitalize the new
issuance costs or continue to amortize the original deferred financing costs and
immediately expense the new issuance costs.
See Notes 12-18 below for a description of each of the Company's debt
obligations.
12. Notes Payable and Borrowings Under Lines of Credit, Notes Payable to
Calpine Capital Trusts and Preferred Interests
The components of notes payable and borrowings under lines of credit and
related outstanding letters of credit are (in thousands):
Letters of Credit
Borrowings Outstanding Outstanding
December 31, December 31,
------------------------- -------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
Corporate Cash Collateralized Letter of Credit Facility ................ $ -- $ -- $ 233,271 $ --
Power Contract Financing, L.L.C ........................................ 688,366 802,246 -- --
Gilroy note payable(1) ................................................. 125,478 132,385 -- --
Siemens Westinghouse Power Corporation ................................. -- 107,994 -- --
Calpine Northbrook Energy Marketing, LLC ("CNEM") note ................. 52,294 74,632 -- --
Corporate revolving lines of credit .................................... -- -- -- 135,600
Power Contract Financing III, LLC ...................................... 51,592 -- -- --
Calpine Commercial Trust ............................................... 34,255 -- -- --
Other .................................................................. 22,280 10,606 6,158 603
---------- ---------- ---------- ----------
Total notes payable and borrowings under lines of credit ............. 974,265 1,127,863 239,429 136,203
Total notes payable to Calpine Capital Trusts ........................ 517,500 1,153,500 -- --
Preferred interest in Saltend Energy Centre ............................ 360,000 -- -- --
Preferred interest in Auburndale Power Plant ........................... 79,135 87,632 -- --
Preferred interest in King City Power Plant ............................ -- 82,000 -- --
Preferred interest in Gilroy Energy Center, LLC ........................ 67,402 74,000 -- --
---------- ---------- ---------- ----------
Total preferred interests ............................................ 506,537 243,632 -- --
Total notes payable and borrowings under lines of credit,
notes payable to Calpine Capital Trusts, preferred interests,
and term loan ....................................................... $1,998,302 $2,524,995 $ 239,429 $ 136,203
========== ========== ========== ==========
Less: notes payable and borrowings under lines of credit, current
portion, notes payable to Calpine Capital Trusts, current portion
and preferred interests, current portion............................ 213,416 265,512
---------- ----------
Notes payable and borrowings under lines of credit, net of current
portion, notes payable to Calpine Capital Trusts, net of current
portion, preferred interests, net of current portion, and term loan... $1,784,886 $2,259,483
========== ==========
- ------------
<FN>
(1) See Note 8 for information regarding this note.
</FN>
Notes Payable and Borrowings Under Lines of Credit and Term Loan
Corporate Cash Collateralized Letter of Credit Facility -- On September 30,
2004, the Company established a new $255 million Cash Collateralized Letter of
Credit Facility with Bayerische Landesbank, under which all letters of credit
previously issued under the $300 million Working Capital Revolver and the $200
million Cash Collateralized Letter of Credit Facility have been transitioned
into that new Facility.
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Power Contract Financing, L.L.C. -- On June 13, 2003, PCF, an indirect
wholly owned subsidiary of Calpine, completed an offering of $339.9 million of
5.2% Senior Secured Notes Due 2006 and $462.3 million of 6.256% Senior Secured
Notes Due 2010. The two tranches of Senior Secured Notes, totaling $802.2
million of gross proceeds, are secured by fixed cash flows from a fixed-priced,
long-term PPA with the State of California Department of Water Resources
("CDWR") and a fixed-priced, long-term power purchase agreement with a third
party and are non- recourse to the Company's other consolidated subsidiaries.
The two tranches of Senior Secured Notes have been rated Baa2 by Moody's
Investor Service, Inc. and BBB (with a negative outlook) by Standard & Poor's
("S&P"). During the year 2004, $113.9 million was repaid based on the agreed
upon bond repayment schedule. The effective interest rates on the 5.2% Senior
Secured Notes Due 2006 and 6.256% Senior Secured Notes Due 2010, after
amortization of deferred financing costs, were 8.3% and 9.4%, respectively, per
annum at December 31, 2004 and 2003.
Pursuant to the applicable transaction agreements, PCF has been established
as an entity with its existence separate from the Company and other subsidiaries
of the Company. In accordance with FIN 46 the Company consolidates this entity.
See Note 2 for more information on FIN 46. The above mentioned power sales and
PPAs, which have been acquired by PCF from CES, and the PCF Notes are assets and
liabilities of PCF, separate from the assets and liabilities of the Company and
other subsidiaries of the Company. The proceeds of the Senior Secured Notes were
primarily used by PCF to purchase the power sales and PPAs.
Siemens Westinghouse Power Corporation -- On January 31, 2002, the
Company's subsidiary, Calpine Construction Management Company, Inc., entered
into an agreement with Siemens Westinghouse Power Corporation ("SWPC") including
vendor financing of up to $232.0 million bearing variable interest for gas and
steam turbine generators and related equipment with monthly payment due dates
through January 28, 2005. The remaining balance under this agreement was repaid
in 2004. The interest rate at December 31, 2004 and 2003, was 8.5%.
Calpine Northbrook Energy Marketing, LLC ("CNEM") Note -- On May 15, 2003,
CNEM, a wholly owned stand-alone subsidiary of CNEM Holdings, LLC, which is a
wholly owned indirect subsidiary of CES, completed an offering of $82.8 million
secured by an existing power sales agreement with the BPA. Under the existing
100-megawatt fixed-price contract, CNEM delivers baseload power to BPA through
December 31, 2006. As a part of the secured transaction, CNEM entered into a
contract with a third party to purchase that power based on spot prices and a
fixed-price swap agreement with an affiliate of Deutsche Bank to lock in the
price of the purchased power. The terms of both agreements are through December
31, 2006. To complete the transactions, CNEM then entered into an agreement with
an affiliate of Deutsche Bank and borrowed $82.8 million secured by the BPA
contract, the spot market PPA, the fixed price swap agreement and the equity
interests in CNEM. The spread between the price for power under the BPA contract
and the price for power under the fixed price swap agreement provides the cash
flow to pay CNEM's debt and other expenses. Proceeds from the borrowing were
used to pay transaction expenses for plant construction and general corporate
purposes, as well as fees and expenses associated with this transaction. CNEM
will make quarterly principal and interest payments on the loan that matures on
December 31, 2006. The effective interest rate, after amortization of deferred
financing charges, was 12.2% and 12.7% per annum at December 31, 2004 and 2003,
respectively.
Pursuant to the applicable transaction agreements, each of CNEM and its
parent, CNEM Holdings, LLC, has been established as an entity with its existence
separate from the Company and other subsidiaries of the Company. In accordance
with FIN 46-R the Company consolidates these entities. The above mentioned power
sales agreement with BPA has been acquired by CNEM from CES and the spot market
PPA with a third party and the swap agreement have been entered into by CNEM
and, together with the $82.8 million loan, are assets and liabilities of CNEM,
separate from the assets and liabilities of the Company and other subsidiaries
of the Company. The only significant asset of CNEM Holdings, LLC is its equity
interest in CNEM. The proceeds of the $82.8 million loan were primarily used by
CNEM to purchase the power sales agreement with BPA.
Corporate Revolving Lines of Credit -- On July 16, 2003, the Company
entered into agreements for a new $500 million working capital facility. This
first-priority senior secured facility consisted of a two-year, $300 million
working capital revolver and a four-year, $200 million term loan that together
provide up to $500 million in combined cash borrowing and letter of credit
capacity. The facility replaced the Company's prior $600 million and $400
million working capital facilities and is secured by a first-priority lien on
the same assets that collateralize the Company's $3.3 billion term loan and
second-priority senior secured notes offering (the "$3.3 billion offering").
On July 16, 2003, the Company entered into a cash collateralized letter of
credit facility with The Bank of Nova Scotia under which it was able to issue up
to $200 million of letters of credit through July 15, 2005. Amounts outstanding
under letters of credit issued under this facility had a corresponding amount of
cash on deposit and held by The Bank of Nova Scotia as collateral, which was
classified as restricted cash in the Company's Consolidated Balance Sheet.
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As a result of the sale of certain natural gas properties during 2004, the
Company repaid all amounts outstanding under its First Priority Senior Secured
Term Loan B Notes Due 2007 and the $300 million Working Capital Revolver.
Power Contract Financing III, LLC -- On June 2, 2004, the Company's wholly
owned subsidiary, PCF III issued $85.0 million of zero coupon notes
collateralized by PCF III's ownership of PCF. PCF III owns all of the equity
interests in PCF, which holds the CDWR I contract monetized in June 2003 and
maintains a debt reserve fund, which had a balance of approximately $94.4
million at December 31, 2004. The Company received cash proceeds of
approximately $49.8 million from the issuance of the notes. At December 31,
2004, the interest rate was 12% per annum.
Calpine Commercial Trust -- In May 2004, in connection with the King City
transaction, Calpine Canada Power Limited, a wholly owned subsidiary of the
Company, entered into a financing with Calpine Commercial Trust. Interest
accrues at 13%, and the loan has principal and interest payments scheduled
through maturity in December 2010. The effective interest rate of this loan is
17%.
Calpine Energy Management, L.P. Letter of Credit Facility -- On August 5,
2004, the Company announced that its newly created entity, Calpine Energy
Management, L.P. ("CEM"), entered into a $250.0 million letter of credit
facility with Deutsche Bank (rated Aa3/AA-) that expires in October 2005.
Deutsche Bank will guarantee CEM's power and gas obligations by issuing letters
of credit. Receivables generated through power sales serve as collateral to
support the letters of credit. As of December 31, 2004, there was approximately
$9.6 million in letters of credit outstanding.
Notes Payable to Calpine Capital Trusts
In 1999 and 2000, the Company, through its wholly owned subsidiaries,
Calpine Capital Trust I, Calpine Capital Trust II, and Calpine Capital Trust
III, statutory business trusts created under Delaware law, (collectively, "the
Trusts") completed offerings of Remarketable Term Income Deferrable Equity
Securities ("HIGH TIDES") at a value of $50.00 per share. A summary of these
offerings follows in the table below ($ in thousands):
Effective Conversion
Interest Rate Ratio --
per Annum Number of
Stated as of Balance Balance Common First Initial
Interest December 31, December 31, December 31, Shares per Redemption Redemption
Issue Date Shares Rate 2004 2004 2003 1 High Tide Date Price
------------ ---------- -------- ------------- ------------ ------------ ----------- ---------- ----------
HIGH TIDES I... October 1999 5,520,000 5.75% 5.38% $ -- $ 276,000 3.4620 November 5, 101.440%
2002
HIGH TIDES II.. January and 7,200,000 5.50% 5.79% -- 360,000 1.9524 February 5, 101.375%
February 2003
2000
HIGH TIDES III. August 2000 10,350,000 5.00% 5.09% 517,500 517,500 1.1510 August 5,
2003 101.250%
---------- --------- ----------
23,070,000 $ 517,500 $1,153,500(1)
========== ========= ==========
- ------------
<FN>
(1) Prior to the adoption of FIN 46 as of December 31, 2003, the Trusts were
consolidated in the Company's Consolidated Balance Sheet, and the HIGH
TIDES were recorded between total liabilities and stockholders equity as
Company-obligated mandatorily redeemable convertible preferred securities
of subsidiary trusts. However, upon adoption of FIN 46 as of December 31,
2003, the Company deconsolidated the Trusts as of October 1, 2003, and
therefore no longer records the HIGH TIDES in its Consolidated Balance
Sheet. As a result, the Company's convertible subordinated debentures (as
discussed below) issued to the Trusts were no longer eliminated in
consolidation and were reflected as notes payable to Calpine Capital Trusts
in the Company's Consolidated Balance Sheet with an outstanding balance of
$1.2 billion and $517.5 million at December 31, 2003 and December 31, 2004,
respectively. During 2003 and 2004, the Company exchanged 30.8 million
Calpine common shares in privately negotiated transactions for
approximately $77.5 million par value of HIGH TIDES I, and $75.0 million of
HIGH TIDES II. The Company also repurchased $115.0 million par value of
HIGH TIDES III for cash of $111.6 million. The repurchased HIGH TIDES III
are reflected in the Company's consolidated balance sheet in Other Assets
as available-for-sale securities as the repurchase did not meet the debt
extinguishment criteria in SFAS No. 140. See Note 2 for further information
regarding the adoption of FIN 46 and Note 3 regarding the Company's
available-for-sale securities.
</FN>
-106-
The net proceeds from each of the offerings were used by the Trusts to
invest in convertible subordinated debentures of the Company, which represent
substantially all of the respective Trusts' assets. The Company effectively
guaranteed all of the respective Trusts' obligations under the trust preferred
securities. The trust preferred securities had or have liquidation values of
$50.00 per share, or $1.2 billion in total for all of the issuances. The Company
had or has the right to defer the interest payments on the debentures for up to
twenty consecutive quarters, which would also cause a deferral of distributions
on the trust preferred securities. Currently, the Company has no intention of
deferring interest payments on the debentures remaining outstanding. The Company
considers the Trusts related parties.
On October 20, 2004, the Company repaid the $276.0 million and $360.0
million convertible subordinate debentures held by Trust I ("HIGH TIDES I") and
Trust II ("HIGH TIDES II") respectively, which used those proceeds to redeem its
outstanding 5 3/4% convertible preferred securities issued by Trust I, and 5
1/2% convertible preferred securities issued by Trust II. The redemption of the
HIGH TIDES I and HIGH TIDES II available-for-sale securities previously
purchased and held by the Company resulted in a realized gain of approximately
$6.1 million. The Company intends to cause both Trusts, which are related
parties, to be terminated.
Preferred Interests
In May 2003, FASB issued SFAS No. 150, which establishes standards for how
an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. SFAS No. 150 applies
specifically to a number of financial instruments that companies have
historically presented within their financial statements either as equity or
between the liabilities section and the equity section, rather than as
liabilities. SFAS No. 150 was effective for financial instruments entered into
or modified after May 31, 2003, and otherwise was effective at the beginning of
the first interim period beginning after June 15, 2003. The Company adopted SFAS
No. 150 on July 1, 2003. For those instruments required to be recoded as debt,
SFAS No. 150 does not permit reclassification of prior period amounts to conform
to the current period presentation. The adoption of SFAS No. 150 and related
balance sheet reclassifications did not have an effect on net income or total
stockholders' equity but have impacted the Company's debt-to-equity and
debt-to-capitalization ratios.
In November 2003, FASB indefinitely deferred certain provisions of SFAS No.
150 as they apply to mandatorily redeemable non-controlling (minority) interests
associated with finite-lived subsidiaries. The Company owns approximately 30% of
CPLP, which is finite-lived, terminating on December 31, 2050. See Note 7 for a
discussion of the Company's investment in CPLP. Upon FASB's finalization of this
issue, the Company may be required to reclassify the minority interest relating
to the Company's investment in Calpine Power Limited Partnership ("CPLP") to
debt. As of December 31, 2004, the minority interest related to CPLP was
approximately $393.4 million. The assets of CPLP are included in the Company's
consolidated balance sheet under the guidance of SFAS No. 66, "Accounting for
Sales of Real Estate" due to the Company's significant continuing involvement in
the assets transferred to CPLP.
Saltend Energy Centre -- On October 26, 2004, the Company, through its
indirect, wholly owned subsidiary Calpine (Jersey) Limited completed a $360
million offering of two-year, Redeemable Preferred Shares. The Redeemable
Preferred Shares will distribute dividends priced at 3-month U.S. LIBOR plus 700
basis points to the shareholders on a quarterly basis. The proceeds of the
offering of the Redeemable Preferred Shares were initially loaned to Calpine's
1,200-megawatt Saltend Energy Centre located in Hull, Yorkshire England, and the
future payments of principal and interest on such loan will fund payments on the
Redeemable Preferred Shares. The net proceeds of the Redeemable Preferred Shares
offering are to be used as permitted by the Company's indentures. The maximum
cost that the Company would incur to repurchase the Redeemable Preferred Shares
at December 31, 2004, is $370.8 million. The effective interest rate, after
amortization of deferred financing charges, was 11.6% per annum at December 31,
2004.
Auburndale Power Plant -- On September 3, 2003, the Company announced that
it had completed the sale of a 70% preferred interest in its Auburndale power
plant to Pomifer Power Funding, LLC, ("PPF"), a subsidiary of ArcLight Energy
Partners Fund I, L.P., for $88.0 million. This preferred interest meets the
criteria of a mandatorily redeemable financial instrument and has been
classified as debt under the guidance of SFAS No. 150, due to certain
preferential distributions to PPF. The preferential distributions are to be paid
quarterly beginning in November 2003 and total approximately $204.7 million over
the 11-year period. The preferred interest holders' recourse is limited to the
net assets of the entity and distribution terms are defined in the agreement.
The Company has not guaranteed the payment of these preferential distributions.
Calpine will hold the remaining interest in the facility and will continue to
provide O&M services. Although the Company cannot readily determine the
potential cost to repurchase the interest in Auburndale Holdings, LLC, the
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carrying value at December 31, 2004, of its aggregate partners' interests was
$79.1 million. The effective interest rate, after amortization of deferred
financing charges, was 17.1% and 16.8% per annum at December 31, 2004 and 2003,
respectively.
King City Power Plant -- On April 29, 2003, the Company sold a preferred
interest in a subsidiary that leases and operates the 120-megawatt King City
Power Plant to GE Structured Finance for $82.0 million. As a result of adopting
SFAS No. 150, approximately $82 million of mandatorily redeemable
non-controlling interest in the King City facility, which had previously been
included within the balance sheet caption "Minority interests," was reclassified
to "Notes payable." The distributions and accretion of issuance costs related to
this preferred interest, which was previously reported as a component of
"Minority interest expense" in the Consolidated Condensed Statements of
Operations, was accounted for as interest expense. Distributions and related
accretion associated with this preferred interest was $5.3 million for the six
months ended December 31, 2003. As of December 31, 2003, there was $82.0 million
outstanding under the preferred interest. The effective interest rate, after
amortization of deferred financing charges, was 13.1% and 12.8% per annum at May
2004 (redemption date) and December 31, 2003, respectively. In connection with
the acquisition of the King City Power Plant by CPIF in May 2004, which was
subject to the Company's pre-existing operating lease, proceeds from the sale of
the Company's Collateral Securities, which supported the lease payments, were
used in part to redeem the balance due under this preferred interest. See Note 3
for a discussion of the Collateral Securities. The Company expensed
approximately $1.2 million in deferred finance costs related to the original
issuance of the preferred interest and paid a $3.0 million termination fee.
These debt extinguishment costs were recorded in Other Expense.
Pursuant to the applicable transaction agreements, each of Calpine King
City Cogen, LLC, Calpine Securities Company, L.P., a parent company of Calpine
King City Cogen, LLC and Calpine King City, LLC, an indirect parent company of
Calpine Securities Company, L.P., has been established as an entity with its
existence separate from the Company and other subsidiaries of the Company. The
Company consolidates these entities.
Gilroy Energy Center, LLC -- On September 30, 2003, GEC, a wholly owned
subsidiary of the Company's subsidiary GEC Holdings, LLC, completed an offering
of $301.7 million of 4% Senior Secured Notes Due 2011 (see Note 16 for more
information on this secured financing). In connection with this secured notes
borrowing, the Company received funding on a third party preferred equity
investment in GEC Holdings, LLC totaling $74.0 million. This preferred interest
meets the criteria of a mandatorily redeemable financial instrument and has been
classified as debt under the guidance of SFAS No. 150, due to certain
preferential distributions to the third party. The preferential distributions
are due semi-annually beginning in March 2004 through September 2011 and total
approximately $113.3 million over the eight-year period. Although the Company
cannot readily determine the potential cost to repurchase the interest in GEC
Holdings, LLC, the carrying value at December 31, 2004, of its aggregate
partners' interests was $67.4 million. The effective interest rate, after
amortization of deferred financing charges, was 12.2% and 11.3% per annum at
December 31, 2004 and 2003, respectively.
Pursuant to the applicable transaction agreements, GEC has been established
as an entity with its existence separate from the Company and other subsidiaries
of the Company. The Company consolidates this entity. The long-term power sales
agreement with the CDWR has been acquired by GEC by means of a series of capital
contributions by CES and certain of its affiliates and is an asset of GEC, and
the Senior Secured Notes and preferred interest are liabilities of GEC, separate
from the assets and liabilities of the Company and other subsidiaries of the
Company. Aside from seven peaker power plants owned directly and the power sales
agreement, GEC's assets include cash and a 100% equity interest in each of Creed
Energy Center, LLC ("Creed") and Goose Haven Energy Center, LLC ("Goose Haven")
each of which is a wholly owned subsidiary of GEC. Each of Creed and Goose Haven
has been established as an entity with its existence separate from the Company
and other subsidiaries of the Company. Creed and Goose Haven each have assets
consisting of various power plants and other assets.
13. Capital Lease Obligations
In the first quarter of 2004, CPIF, a related party, acquired the King City
power plant from a third party in a transaction that closed May 19, 2004. See
Note 9 for a discussion of the Company's relationship with CPIF. CPIF became the
new lessor of the facility, which it purchased subject to the Company's
pre-existing operating lease. The Company restructured certain provisions of the
operating lease, including a 10-year extension and the elimination of the
collateral requirements necessary to support the original lease payments. The
base term of the restructured lease expires in 2028 with a renewal option at the
then fair market rental value of the facility. See Note 3 for more information
on the elimination of the collateral requirements. Due to the lease extension
and other modifications to the original lease, the lease was reevaluated under
SFAS No. 13 and determined to be a capital lease. The present value of the
minimum lease payments totaled approximately $114.9 million which represented
-108-
more than 90% of the fair value of the facility. As a result, the Company
recorded a capital lease asset of $114.9 million as property, plant and
equipment in the Consolidated Balance Sheet. This asset will be depreciated over
the 24 year base lease term. In recording the capital lease obligation, the
outstanding deferred lease incentive liability ($53.7 million including the
current portion as of December 31, 2003) recorded as part of the original
operating lease transaction, and the prepaid operating lease payments asset
($69.4 million including the current portion as of December 31, 2003)
accumulated under the original operating lease terms, were eliminated. The
difference between these two balances on May 19, 2004 was approximately $19.9
million and is reflected as a discount to the $114.9 million capital lease
obligation. This discount will be accreted as additional interest expense using
the effective interest method over the 24 year lease term. The net capital lease
obligation originally recorded as debt in the Consolidated Balance Sheet was
$94.9 million.
The Company assumed and consolidated its other capital leases in
conjunction with certain acquisitions that occurred during 2001. As of December
31, 2004 and 2003, the asset balances for the leased assets totaled $322.3
million and $201.5 million, respectively, with accumulated amortization of $41.8
million and $26.0 million, respectively. Of these balances as of December 31,
2004, $114.9 million of leased assets and $2.7 million of accumulated
amortization related to the King City power plant, which is leased from a
related party. The primary types of property leased by the Company are power
plants and related equipment. The leases generally provide for the lessee to pay
taxes, maintenance, insurance, and certain other operating costs of the leased
property. The lease terms range up to 28 years. Some of the lease agreements
contain customary restrictions on dividends, additional debt and further
encumbrances similar to those typically found in project financing agreements.
In determining whether a lease qualifies for capital lease treatment, in
accordance with SFAS No. 13, the Company includes all increases due to step rent
provisions/escalation clauses in its minimum lease payments for its capital
lease obligations. Certain capital improvements associated with leased
facilities may be deemed to be leasehold improvements and are amortized over the
shorter of the term of the lease or the economic life of the capital
improvement. Lease concessions including taxes and insurance are excluded from
the minimum lease payments. The Company's minimum lease payments are not tied to
an existing variable index or rate.
The following is a schedule by years of future minimum lease payments under
capital leases together with the present value of the net minimum lease payments
as of December 31, 2004 (in thousands):
King City
Capital Lease Other
with related Capital
party Leases Total
------------- ----------- -----------
Years Ending December 31:
2005................................................................................. $ 16,699 $ 19,154 $ 35,853
2006................................................................................. 16,458 19,760 36,218
2007................................................................................. 16,552 19,918 36,470
2008................................................................................. 16,199 21,753 37,952
2009................................................................................. 16,592 21,600 38,192
Thereafter........................................................................... 175,492 268,317 443,809
----------- ----------- -----------
Total minimum lease payments........................................................ 257,992 370,502 628,494
Less: Amount representing interest(1).................................................. 162,095 177,480 339,575
----------- ----------- -----------
Present value of net minimum lease payments.......................................... 95,897 193,022 288,919
Less: Capital lease obligation, current portion........................................ 1,199 4,291 5,490
----------- ----------- -----------
Capital lease obligation, net of current portion..................................... $ 94,698 $ 188,731 $ 283,429
============ =========== ===========
- ------------
<FN>
(1) Amount necessary to reduce net minimum lease payments to present value
calculated at the incremental borrowing rate at the time of acquisition.
</FN>
-109-
14. CCFC I Financing
The components of CCFC I financing as of December 31, 2004 and 2003, are
(in thousands):
Outstanding at
December 31,
------------------------
2004 2003
----------- -----------
Calpine Construction Finance Company I Second Priority Senior Secured Floating Rate Notes Due 2011...... $ 408,568 $ 407,598
First Priority Secured Institutional Term Loans Due 2009.............................................. 378,182 381,391
----------- -----------
Total................................................................................................ 786,750 788,989
Less: Current portion................................................................................... 3,208 3,208
----------- -----------
CCFC I financing, net of current portion................................................................ $ 783,542 $ 785,781
=========== ===========
In November 1999, the Company entered into a credit agreement for $1.0
billion through its wholly owned subsidiary CCFC I with a consortium of banks.
The lead arranger was The Bank of Nova Scotia and the lead arranger syndication
agent was Credit Suisse First Boston. The non-recourse credit facility was
utilized to finance the construction of certain of the Company's gas-fired power
plants. The Company repaid the outstanding balance of $880.1 million in August
2003.
On August 14, 2003, the Company's wholly owned subsidiaries, CCFC I and
CCFC Finance Corp., closed a $750.0 million institutional term loans and secured
notes offering, proceeds from which were utilized to repay a majority of CCFC
I's indebtedness which would have matured in the fourth quarter of 2003. The
offering included $385.0 million of First Priority Secured Institutional Term
Loans Due 2009 (the "CCFC I Term Loans") offered at 98% of par and priced at
LIBOR plus 600 basis points, with a LIBOR floor of 150 basis points, and $365.0
million of Second Priority Senior Secured Floating Rate Notes Due 2011 (the
"CCFC I Senior Notes") offered at 98.01% of par and priced at LIBOR plus 850
basis points, with a LIBOR floor of 125 basis points. On September 25, 2003,
CCFC I and CCFC Finance Corp. closed on an additional $50.0 million of the CCFC
I Senior Notes offered at 99% of par. The noteholders' recourse is limited to
seven of CCFC I's natural gas-fired electric generating facilities located in
various power markets in the United States, and related assets and contracts.
S&P has assigned a B corporate credit rating to CCFC I. S&P also assigned a B+
rating (with a negative outlook) to the CCFC I Term Loans and a B-- rating (with
a negative outlook) to the CCFC I Senior Notes. The interest rate of the CCFC I
Senior Notes was 10.5% at December 31, 2004, and 9.8% at December 31, 2003. The
effective interest rate, after amortization of deferred financing costs, was
10.8% per annum at December 31, 2004, and 10.0% at December 31, 2003. The
interest rate of the CCFC I Term Loans was 8.4% at December 31, 2004, and 7.5%
at December 31, 2003. The effective interest rate, after amortization of
deferred financing costs, was 8.5% per annum at December 31, 2004, and 8.2% at
December 31, 2003.
15. CalGen/CCFC II Financing
The components of CalGen/CCFC II financing as of December 31, 2004 and
2003, are (in thousands):
Letters of Credit
Outstanding at Outstanding at
December 31, December 31,
-------------------------- --------------------------
2004 2003 2004 2003
------------ ------------ ------------ ------------
Calpine Generating Company, LLC
Third Priority Secured Floating Rate Notes Due 2011...................... $ 680,000 $ -- $ -- $ --
Second Priority Secured Floating Rate Notes Due 2010..................... 631,639 -- -- --
First Priority Secured Term Loans Due 2009............................... 600,000 -- -- --
First Priority Secured Floating Rate Notes Due 2009...................... 235,000 -- -- --
Third Priority Secured Fixed Rate Notes Due 2011......................... 150,000 -- -- --
Second Priority Secured Term Loans Due 2010.............................. 98,693 -- -- --
First Priority Secured Revolving Loans................................... -- -- 189,958 --
Calpine Construction Finance Company II Revolver........................... -- 2,200,358 -- 53,190
------------ ------------ ------------ -----------
Total CalGen/CCFC II financing............................................. $ 2,395,332 $ 2,200,358 $ 189,958 $ 53,190
============ ============ ============ ===========
-110-
In October 2000, the Company entered into a credit agreement for $2.5
billion through its wholly owned subsidiary Calpine Construction Finance Company
II, LLC ("CCFC II") with a consortium of banks. The lead arrangers were The Bank
of Nova Scotia and Credit Suisse First Boston. The non-recourse credit facility
was utilized to finance the construction of certain of the Company's gas-fired
power plants. The interest rate at December 31, 2003 was 2.6%. The interest rate
ranged from 2.6% to 4.8% during 2004 and 2.6% to 2.9% during 2003. The effective
interest rate, after amortization of deferred financing costs, was 7.2% and 3.4%
per annum at December 31, 2004 and 2003, respectively.
On March 23, 2004, the Company's wholly owned subsidiary Calpine Generating
Company, LLC ("CalGen"), formerly known as CCFC II, completed its offering of
secured term loans and secured notes. As expected, the Company realized net
total proceeds from the offerings (after payment of transaction fees and
expenses, including the fee payable to Morgan Stanley in connection with an
index hedge) in the approximate amount of $2.3 billion. The interest rates
associated with the instruments are as follows:
Description Interest Rate
- --------------------------------------------------------------------- ------------------------------
First Priority Secured Floating Rate Notes Due 2009.................. LIBOR plus 375 basis points
Second Priority Secured Floating Rate Notes Due 2010................. LIBOR plus 575 basis points
Third Priority Secured Floating Rate Notes Due 2011.................. LIBOR plus 900 basis points
Third Priority Secured Notes Due 2011................................ 11.50%
First Priority Secured Term Loans due 2009........................... LIBOR plus 375 basis points(1)
Second Priority Secured Term Loans due 2010.......................... LIBOR plus 575 basis points(2)
- ------------
<FN>
(1) The Company may also elect a Base Rate plus 275 basis points.
(2) The Company may also elect a Base Rate plus 475 basis points.
</FN>
The secured term loans and secured notes described above in each case are
collateralized, through a combination of pledges of the equity interests in
CalGen and its first tier subsidiary, CalGen Expansion Company, liens on the
assets of CalGen's power generating facilities (other than its Goldendale
facility) and related assets located throughout the United States. The lenders'
recourse is limited to such collateral, and none of the indebtedness is
guaranteed by Calpine. Net proceeds from the offerings were used to refinance
amounts outstanding under the $2.5 billion CCFC II revolving construction credit
facility, which was scheduled to mature in November 2004, and to pay fees and
transaction costs associated with the refinancing. Concurrently with this
refinancing, the Company amended and restated the CCFC II credit facility (as
amended and restated, the "CalGen revolving credit facility") to reduce the
commitments under the facility to $200.0 million and extend its maturity to
March 2007. Borrowings under the CalGen revolving credit facility bear interest
at LIBOR plus 350 basis points (or, at the Company's election, the Base Rate
plus 250 basis points). Interest rates and effective interest rates, after
amortization of deferred financing costs are as follows:
2004 Effective Interest
Interest Rate at Rate after Amortization of
December 31, 2004 Deferred Financing Costs
----------------- --------------------------
First Priority Secured Floating Rate Notes Due 2009................................. 6.0% 5.8%
Second Priority Secured Floating Rate Notes Due 2010................................ 8.0% 8.1%
Third Priority Secured Floating Rate Notes Due 2011................................. 11.2% 10.9%
Third Priority Secured Fixed Rate Notes Due 2011.................................... 11.5% 11.8%
First Priority Secured Term Loans Due 2009.......................................... 6.0% 5.8%
Second Priority Secured Term Loans Due 2010......................................... 8.0% 8.0%
First Priority Secured Revolving Loans.............................................. -- 17.5%
-111-
16. Other Construction/Project Financing
The components of the Company's other construction/project financing as of
December 31, 2004 and 2003, are (in thousands):
Letters of Credit
Outstanding at Outstanding at
December 31, December 31,
-------------------------- --------------------------
Projects 2004 2003 2004 2003
- -------------------------------------------------------------------------- ------------ ------------ ------------ ------------
Riverside Energy Center, LLC.............................................. $ 368,500 $ 165,347 $ -- $ --
Pasadena Cogeneration, L.P................................................ 282,896 289,115 -- --
Broad River Energy LLC.................................................... 275,112 291,612 -- --
Fox Energy Company LLC.................................................... 266,075 -- 75,000 --
Rocky Mountain Energy Center, LLC......................................... 264,900 -- -- --
Gilroy Energy Center, LLC, 4% Senior Secured Notes Due 2011............... 261,382 298,065 -- --
Aries Power Plant......................................................... 174,914 -- -- --
Blue Spruce Energy Center, LLC............................................ 98,272 140,000 -- --
Otay Mesa Energy Center, LLC -- Ground Lease.............................. 7,000 7,000 -- --
Calpine Newark, LLC....................................................... -- 47,816 -- --
Calpine Parlin, LLC....................................................... -- 32,451 -- --
------------ ------------ ------------ ------
Total................................................................... 1,999,051 1,271,406 $ 75,000 $ --
============ ======
Less: Current portion..................................................... 93,393 61,900
------------ ------------
Long-term construction/project financing.................................. $ 1,905,658 $ 1,209,506
============ ============
Riverside Energy Center -- On August 25, 2003, the Company announced that
it had completed a $230.0 million non-recourse project financing for its
603-megawatt Riverside Energy Center. The natural gas-fueled electric generating
facility is currently under construction in Beloit, Wisconsin. Upon completion
of the project, which was scheduled for June 2004, Calpine was required to sell
450 megawatts of electricity to Wisconsin Power and Light under the terms of a
nine-year tolling agreement and provide 75 megawatts of capacity to Madison Gas
& Electric under a nine-year power sales agreement. A group of banks, including
Credit Lyonnais, Co-Bank, Bayerische Landesbank, HypoVereinsbank and NordLB,
were to finance construction of the plant at a rate of Libor plus 250 basis
points. Upon commercial operation of the Riverside Energy Center, the banks were
required to provide a three-year term-loan facility initially priced at Libor
plus 275 basis points. The interest rate at refinancing on June 29, 2004, and
December 31, 2003, was 3.7%. The interest rate ranged from 3.6% to 3.7% during
2004. The effective interest rate, after amortization of deferred financing
costs, was 4.7% and 5.3% per annum at refinancing on June 29, 2004, and December
31, 2003, respectively. This facility was refinanced along with Rocky Mountain
on June 29, 2004.
Pasadena Cogeneration, L.P. -- In September 2000, the Company completed the
financing, which matures in 2048, for both Phase I and Phase II of the Pasadena,
Texas cogeneration project. Under the terms of the project financing, the
Company received $400.0 million in gross proceeds. The interest rate at December
31, 2004 and 2003, was 8.6%.
Broad River Energy LLC -- In October 2001, the Company completed the
financing, which matures in 2041, for the Broad River Energy Center in South
Carolina. Under the terms of the project financing, the Company received $300.0
million in gross proceeds. The interest rate at December 31, 2004 and 2003, was
7.9% and 8.1%, respectively.
Fox Energy Company LLC -- On November 19, 2004, the Company entered into a
$400 million, 25-year, non-recourse sale/leaseback transaction with affiliates
of GE Commercial Finance Energy Financial Services ("GECF") for the 560-megawatt
Fox Energy Center under construction in Wisconsin. The proceeds will be used to
reimburse Calpine for construction capital spent to date on the project, to
repay existing debt associated with equipment for the project and to complete
the construction of the facility. Once construction is complete, the Company
will lease the power plant from GECF under a 25-year facility lease. The Company
also has an option to renew the lease for a 15-year term. Due to significant
continuing involvement, as defined in SFAS No. 98, "Accounting for Leases," the
transaction does not currently qualify for sale lease-back accounting under that
statement and has been accounted for as a financing. The proceeds received from
GECF are recorded as debt in the Company's consolidated balance sheet. The power
plant assets will be depreciated over their estimated useful life and the lease
payments will be applied to principal and interest expense using the effective
interest method until such time as the Company's continuing involvement is
removed, expires or is otherwise eliminated. Once the Company no longer has
significant continuing involvement in the power plant assets, the legal sale
will be recognized for accounting purposes and the underlying lease will be
evaluated and classified in accordance with SFAS No. 13. The effective interest
rate at December 31, 2004 was 7.1%.
-112-
Rocky Mountain Energy Center, LLC -- On February 20, 2004, the Company
completed a $250.0 million, non-recourse project financing for the 621-megawatt
Rocky Mountain Energy Center. A consortium of banks financed the construction of
the plant at a rate of LIBOR plus 250 basis points. This loan was refinanced in
June 2004, as described below.
Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC -- On
June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy Center,
LLC, wholly owned stand-alone subsidiaries of the Company's Calpine Riverside
Holdings, LLC subsidiary, received funding in the aggregate amount of $661.5
million comprised of $633.4 million of First Priority Secured Floating Rate Term
Loans Due 2011 priced at LIBOR plus 425 basis points and $28.1 million letter of
credit-linked deposit facility. Net proceeds from the loans, after transaction
costs and fees, were used to pay final construction costs and refinance amounts
outstanding under the $250 million non-recourse project financing for the Rocky
Mountain facility and the $230 million non-recourse project financing for the
Riverside facility. In connection with this refinancing, the Company wrote off
$13.2 million in deferred financing costs. In addition, approximately $160.0
million was used to reimburse the Company for costs incurred in connection with
the development and construction of the Rocky Mountain and Riverside facilities.
The Company also received approximately $79.0 million in proceeds via a
combination of cash and increased credit capacity as a result of the elimination
of certain reserves and cancellation of letters of credit associated with the
original non-recourse project financings. The interest rate of the Rocky
Mountain facility at December 31, 2004, was 8.6%. The interest rate of the
Riverside facility at December 31, 2004 was 6.4%.
Gilroy Energy Center, LLC -- On September 30, 2003, GEC, a wholly owned,
stand-alone subsidiary of the Company's subsidiary GEC Holdings, LLC, closed on
$301.7 million of 4% Senior Secured Notes Due 2011. The senior secured notes are
secured by GEC's and its subsidiaries' 11 peaking units located at nine
power-generating sites in northern California. The notes also are secured by a
long-term power sales agreement for 495 megawatts of peaking capacity with the
CDRW, which is being served by the 11 peaking units. In addition, payment of the
principal and interest on the notes when due is insured by an unconditional and
irrevocable financial guaranty insurance policy that was issued simultaneously
with the delivery of the notes. Proceeds of the notes offering (after payment of
transaction expenses, including payment of the financial guaranty insurance
premium, which are capitalized and included in deferred financing costs on the
balance sheet) will be used to reimburse costs incurred in connection with the
development and construction of the peaker projects. The noteholders' recourse
is limited to the financial guaranty insurance policy and, insofar as payment
has not been made under such policy, to the assets of GEC and its subsidiaries.
The Company has not guaranteed repayment of the notes. The effective interest
rate, after amortization of deferred financing charges, was 6.7% and 5.1% per
annum at December 31, 2004 and 2003, respectively. In connection with this
offering, the Company has received funding on a third party preferred equity
investment in GEC Holdings, LLC totaling $74.0 million. See Note 12 for more
information regarding this preferred interest.
Aries Power Plant -- On March 26, 2004, in connection with the closing of
the acquisition of the Aries Power Plant, the existing construction loan was
converted to two term loans totaling $178.8 million. At December 31, 2004,
Tranche A had an aggregate principal amount of $126.8 million, with quarterly
payments maturing in December 2016. At December 31, 2004, Tranche B had an
aggregate principal amount of $48.1 million, with quarterly payments maturing in
December 2019. After taking interest rate swaps into consideration, the interest
rates on Tranches A and B were 9.25% and 10.32%, respectively.
Blue Spruce Energy Center, LLC -- On August 22, 2002, the Company completed
a $106.0 million non-recourse project financing for the construction of its
285-megawatt Blue Spruce Energy Center. On November 7, 2003, the Company repaid
the outstanding balance of $102.0 million with the proceeds of a new term
financing described below.
On November 7, 2003, the Company completed a new $140.0 million term loan
financing for the Blue Spruce Energy Center. The term loan is made up of two
facilities, Tranche A and Tranche B, which have 15-year and 6-year repayment
terms, respectively. At December 31, 2004, there was $98.3 million outstanding
under Tranche A while Tranche B was repaid. The effective interest rate, after
amortization of deferred financing costs, for Tranche A and Tranche B was 8.2%
and 8.6%, respectively, per annum at December 31, 2003. The effective interest
rate, after amortization of deferred financing costs, for Tranche A was 14.4%
per annum at December 31, 2004.
Otay Mesa Energy Center, LLC -- On July 8, 2003, Otay Mesa Generating
Company, LLC, entered into a ground lease and easement agreement with D&D
Landholdings, a Limited Partnership. The interest rate at December 31, 2004 and
2003 was 12.6%.
Calpine Newark, LLC and Calpine Parlin, LLC -- In December 2002, the
Company completed a $50.0 million project financing secured by the Newark Power
Plant. This financing was fully repaid in May 2004 in connection with the
contract termination discussed below. The interest rate at repayment in May 2004
and at December 31, 2003, was 10.6%.
-113-
In December 2002, the Company completed a $37.0 million project financing
secured by the Parlin Power Plant. This financing was fully repaid in May 2004
in connection with the contract termination discussed below. The interest rate
at repayment in May 2004 and at December 31, 2003, was 9.8%.
On May 26, 2004, the Company and Jersey Central Power & Light Company
("JCPL") terminated their existing toll arrangements with the Newark and Parlin
power plants, resulting in a pre-tax gain of $100.6 million. Proceeds from this
transaction were used to retire project financing debt of $78.8 million. In
conjunction with this termination, Utility Contract Funding II, LLC ("UCF"), a
wholly owned subsidiary of CES, entered into a long-term PPA with JCPL. UCF was
then sold. The Company recognized an $85.4 million pre-tax gain on the sale of
UCF. The total pre-tax gain, net of transaction costs and the write-off of
unamortized deferred financing costs, was $171.5 million.
California Peaker Financing -- On May 14, 2002, the Company's subsidiary,
Calpine California Energy Finance, LLC, entered into an $100.0 million amended
and restated credit agreement with ING Capital LLC for the funding of 9
California peaker facilities, of which $100.0 million was drawn on May 24, 2002,
and $50.0 million was repaid on August 7, 2002, and the remaining $50.0 million
was repaid on July 21, 2003. The interest rate ranged from 3.5% to 3.9% during
2003. The effective interest rate, after amortization of deferred financing
costs, was 4.0% per annum at December 31, 2003.
17. Convertible Senior Notes
4% Convertible Senior Notes Due 2006
In December 2001 and January 2002, the Company completed the issuance of
$1.2 billion in aggregate principal amount of 4% Convertible Senior Notes Due
2006 ("2006 Convertible Senior Notes"). These securities are convertible, at the
option of the holder, into shares of Calpine common stock at a price of $18.07.
Holders had the right to require the Company to repurchase all or a portion of
the 2006 Convertible Senior Notes on December 26, 2004, at 100% of their
principal amount plus any accrued and unpaid interest. The Company can
repurchase the 2006 Convertible Senior Notes with cash, shares of Calpine common
stock, or a combination of cash and stock. During 2004 and 2003 the Company
repurchased approximately $658.7 million and $474.9 million in aggregate
outstanding principal amount of the 2006 Convertible Senior Notes at a
repurchase price of $657.7 million and $458.8 million plus accrued interest,
respectively. Additionally, during 2003 approximately $65.0 million in aggregate
outstanding principal amount of the 2006 Convertible Senior Notes were exchanged
for 12.0 million shares of Calpine common stock in privately negotiated
transactions. During 2004 and 2003 the Company recorded a pre-tax loss of $5.3
million and a pre-tax gain of $13.6 million, respectively, on these
transactions, net of write-offs of the associated unamortized deferred financing
costs and unamortized premiums or discounts. The effective interest rate on
these notes at December 31, 2004 and 2003, after amortization of deferred
financing costs, was 4.6% and 4.9% per annum, respectively. At December 31,
2004, approximately $1.3 million of the 2006 Convertible Senior Notes remain
outstanding.
4 3/4% Contingent Convertible Senior Notes Due 2023
On November 17, 2003, the Company completed the issuance of $650 million of
2023 Convertible Senior Notes. These 2023 Convertible Senior Notes are
convertible, at the option of holder, into cash and into shares of Calpine
common stock at a price of $6.50 per share, which represents a 38% premium over
the New York Stock Exchange closing price of $4.71 per Calpine common share on
November 6, 2003. Holders have the right to require the Company to repurchase
all or a portion of these securities on November 15, 2009, November 15, 2013,
and November 15, 2018, at 100% of their principal amount plus any accrued and
unpaid interest and liquidated damages, if any, up to the date of repurchase.
Otherwise, conversion is subject to a common stock price condition where the
Company's common stock is trading for at least 20 trading days in the period of
30 consecutive trading days ending on the last trading day of the calendar
quarter preceding the quarter in which the conversion occurs is more than 120%
of the conversion price per share of the common stock in effect on that 30th
trading day. Conversion is also subject to a trading price condition where
during the five trading day period after any five consecutive trading day period
in which the trading price of $1,000 principal amount of the notes for each day
of such five-day period was less than 95% of the product of the closing sale
price of our common stock price on that day multiplied by the Conversion Rate.
Note holders have a limited amount of time to convert their notes once a
conversion condition has been achieved. Generally, upon conversion of the notes
the Company is required to deliver the par value of the notes in cash and any
additional conversion value in Calpine common stock. However, if the notes are
put back to the Company on November 15, 2009, November 15, 2013 or November 15,
2018, the Company has the right to pay the repurchase price in cash, shares of
Calpine common stock, or a combination of cash and stock.
-114-
On January 9, 2004, one of the initial purchasers of the 2023 Convertible
Senior Notes exercised in full its option to purchase an additional $250.0
million of these notes. The notes are convertible into cash and into shares of
Calpine common stock upon the occurrence of certain contingencies at an initial
conversion price of $6.50 per share, which represents a 38% premium over the New
York Stock Exchange closing price of $4.71 per share on November 6, 2003, the
date the notes were originally priced.
During 2004, the Company repurchased approximately $266.2 million in
aggregate outstanding principal amount of 2023 Convertible Senior Notes at a
repurchase price of $177.0 million plus accrued interest. At December 31, 2004,
there was $633.8 million in outstanding borrowings under these notes. The
effective interest rate on these notes, after amortization of deferred financing
costs, was approximately 5.3% and 4.9% per annum at December 31, 2004 and 2003.
6% Contingent Convertible Notes Due 2014
On September 30, 2004, the Company closed on $736 million aggregate
principal amount at maturity of 2014 Convertible Notes, offered at 83.9% of par.
Net proceeds were used to repurchase certain outstanding Senior Notes, 2023
Convertible Senior Notes, and HIGH TIDES securities. The Company recorded a
pre-tax gain on these transactions in the amount of $167.2 million, net of
write-offs of unamortized deferred financing costs and the unamortized premiums
or discounts.
The 2014 Convertible Notes are convertible into cash and into a variable
number of shares of Calpine common stock based on a conversion value derived
from the conversion price of $3.85 per share. The number of shares to be
delivered upon conversion will be determined by the market price of Calpine
common shares at the time of conversion. However, conversion is subject to a
common stock price condition where the Company's common stock is trading for at
least 20 trading days in the period of 30 consecutive trading days ending on the
last trading day of the calendar quarter preceding the quarter in which the
conversion occurs is more than 120% of the conversion price per share of the
common stock in effect on the 30th trading day. Conversion is also subject to a
trading price condition where during the five trading day period after any five
consecutive trading day period in which the trading price of $1,000 principal
amount at maturity of the notes for each day of such five-day period was less
than 95% of the product of the closing sale price of our common stock price on
that day multiplied by the Conversion Rate. Note holders have a limited amount
of time to convert their notes once a conversion condition has been achieved.
The conversion price of $3.85 per share represents a premium of
approximately 23% over The New York Stock Exchange closing price of $3.14 per
Calpine common share on September 27, 2004. The 2014 Convertible Notes will pay
Contractual cash interest at a rate of 6%, except that in years three, four and
five, in lieu of interest, the original principal amount of $839 per note will
accrete daily beginning September 30, 2006, to the full principal amount of
$1,000 per note at September 30, 2009. For accounting purposes, the Company has
calculated the effective interest rate of the 2014 Convertible Notes capturing
the 6% stated rate and the 16.1% discount and is recording interest expense over
the 10-year term of the instrument using the effective interest method in
accordance with paragraph 13-15 of APB Opinion No. 21, "Interest on Receivables
and Payables." Upon conversion of the 2014 Convertible Notes, the Company is
required to deliver the accreted principal amount of the notes in cash and any
additional conversion value in Calpine common stock. However, in certain events
of default the Company is required to deliver the par value of the notes in
Calpine common stock.
At December 31, 2004, there was $620.2 million in outstanding borrowings
under these notes. The effective interest rate on these notes, after
amortization of deferred financing costs, was approximately 6.3% per annum at
December 31, 2004.
In conjunction with the 2014 Convertible Notes offering, the Company
entered into a ten-year Share Lending Agreement with Deutsche Bank AG London
("DB London"), under which the Company loaned DB London 89 million shares of
newly issued Calpine common stock (the "loaned shares") in exchange for a loan
fee of $.001 per share. DB London sold the entire 89 million shares on September
30, 2004, at a price of $2.75 per share in a registered public offering. The
Company did not receive any of the proceeds of the public offering. DB London is
required to return the loaned shares to the Company no later than the end of the
ten-year term of the Share Lending Agreement, or earlier under certain
circumstances. Once loaned shares are returned, they may not be re-borrowed
under the Share Lending Agreement. Under the Share Lending Agreement, DB London
is required to post and maintain collateral in the form of cash, government
securities, certificates of deposit, high-grade commercial paper of U.S. issuers
or money market shares at least equal to 100% of the market value of the loaned
shares as security for the obligation of DB London to return the loaned shares
to the Company. This collateral is held in an account at a DB London affiliate.
The Company has no access to the collateral unless DB London defaults under its
obligations.
-115-
The Share Lending Agreement is similar to an accelerated share repurchase
transaction which is addressed by EITF Issue No. 99-07, "Accounting for an
Accelerated Share Repurchase Program." This EITF issue requires an accelerated
share repurchase transaction to be accounted for as two transactions: a treasury
stock purchase and a forward sales contract. The Share Lending Agreement
involved the issuance of 89 million shares of the Company's common stock in
exchange for a physically settling forward contract for the reacquisition of the
shares at a future date. We recorded the issuance of shares in equity at the
fair value of the Calpine common stock on the date of issuance in the amount of
$258.1 million. As there was minimal cash consideration in the transaction, the
requirement to the return of these shares is considered to be a prepaid forward
purchase contract. We have evaluated the prepaid forward contract under the
guidance of SFAS No. 133, and determined that the instrument was not a
derivative in its entirety and that the embedded derivative would not require
separate accounting. The hybrid contract was classified similar to a shareholder
loan which was recorded in equity at the fair value of the Calpine common stock
on the date of issuance in the amount of $258.1 million.
Under SFAS No. 150, entities that have entered into a forward contract that
requires physical settlement by repurchase of a fixed number of the issuer's
equity shares of common stock in exchange for cash shall exclude the common
shares to be redeemed or repurchased when calculating basic and diluted EPS. The
Share Lending Agreement does not provide for cash settlement, but rather
physical settlement is required (i.e. the shares must be returned by the end of
the arrangement). The Company analogizes to the guidance in SFAS No. 150 such
that the prepaid forward contract results in a reduction in the number of
outstanding shares used to calculate basic and diluted EPS. Consequently, the 89
million shares of common stock subject to the Share Lending Agreement are
excluded from the earnings per share EPS calculation.
-116-
18. Senior Notes
Senior Notes payable consist of the following as of December 31, 2004 and
2003, (in thousands):
Fair Value as of
First December 31, December 31, (3)
Interest Call ---------------------- --------------------
Rates Date 2004 2003 2004 2003
-------- ----- ---------- ---------- ---------- ----------
First Priority Senior Secured Notes
First Priority Senior Secured Notes Due 2014................ 95/8% (12) $ 778,971 $ -- $ 801,367 $ --
---------- ---------- ---------- ----------
First Priority Senior Secured Term Loan B Notes Due 2007.... (4) (2) -- 199,500 -- 202,243
---------- ---------- ---------- ----------
Total First Priority Senior Secured Notes.................. 778,971 199,500 801,367 202,243
---------- ---------- ---------- ----------
Second Priority Senior Secured Notes........................
Second Priority Senior Secured Term Loan B Notes Due 2007... (5) (8) 740,625 748,125 677,672 727,552
Second Priority Senior Secured Floating Rate Notes Due 2007. (6) (7) 493,750 498,750 449,313 488,775
Second Priority Senior Secured Notes Due 2010............... 81/2% (7) 1,150,000 1,150,000 987,563 1,127,000
Second Priority Senior Secured Notes Due 2013............... 83/4% (7) 900,000 900,000 740,250 877,500
Second Priority Senior Secured Notes Due 2011............... 97/8% (1) 393,150 392,159 344,006 401,963
---------- ---------- ---------- ----------
Total Second Priority Senior Secured Notes................. 3,677,525 3,689,034 3,198,804 3,622,790
---------- ---------- ---------- ----------
Unsecured Senior Notes
Senior Notes Due 2005....................................... 81/4% (2) 185,949 224,679 188,424 215,692
Senior Notes Due 2006....................................... 101/2% 2001 152,695 166,575 151,359 163,243
Senior Notes Due 2006....................................... 75/8% (1) 111,563 214,613 109,332 191,006
Senior Notes Due 2007....................................... 83/4% 2002 195,305 226,120 177,728 187,679
Senior Notes Due 2007(9).................................... 83/4% (2) 165,572 154,120 150,671 114,049
Senior Notes Due 2008....................................... 77/8% (1) 227,071 305,323 191,875 236,624
Senior Notes Due 2008....................................... 81/2% (2) 1,581,539 1,925,067 1,347,472 1,540,053
Senior Notes Due 2008(10)................................... 83/8% (2) 160,050 154,140 121,638 114,064
Senior Notes Due 2009....................................... 73/4% (1) 221,539 232,520 177,231 179,041
Senior Notes Due 2010....................................... 85/8% (2) 496,973 496,909 402,548 390,074
Senior Notes Due 2011....................................... 81/2% (2) 1,063,850 1,179,911 792,568 932,130
Senior Notes Due 2011(11)................................... 87/8% (2) 232,511 215,242 167,989 157,127
---------- ---------- ---------- ----------
Total Unsecured Senior Notes............................... 4,794,617 5,495,219 3,978,835 4,420,782
---------- ---------- ---------- ----------
Total Senior Notes........................................ 9,251,113 9,383,753 7,979,006 8,245,815
---------- ---------- ---------- ----------
Less: Senior Notes, current portion....................... 718,449 14,500 198,449 14,500
---------- ---------- ---------- ----------
Senior Notes, net of current portion..................... $8,532,664 $9,369,253 $7,780,557 $8,231,315
========== ========== ========== ==========
- ------------
<FN>
(1) Not redeemable prior to maturity.
(2) Redeemable by the Company at any time prior to maturity.
(3) Represents the market values of the Senior Notes at the respective dates.
(4) 3-month US$ LIBOR, plus a spread.
(5) U.S. Prime Rate in combination with the Federal Funds Effective Rate, plus
a spread.
(6) British Bankers Association LIBOR Rate for deposit in U.S. dollars for a
period of three months, plus a spread.
(7) At any time before July 15, 2005, with respect to the Second Priority
Senior Secured Floating Rate Notes Due 2007 (the "2007 notes") and before
July 15, 2006, with respect to the Second Priority Senior Secured Notes Due
2010 (the "2010 notes") and the Second Priority Senior Secured Notes Due
2013 (the "2013 notes"), on one or more occasions, the Company can choose
to redeem up to 35% of the outstanding principal amount of the applicable
series of notes, including any additional notes issued in such series, with
the net cash proceeds of any one or more public equity offerings so long as
(1) the Company pays holders of the notes a redemption price equal to par
plus the applicable Eurodollar rate then in effect with respect to the 2007
notes, 108.500% with respect to the 2010 notes, and 108.750% with respect
to the 2013 notes, at the face amount of the notes the Company redeems,
plus accrued interest; (2) the Company must redeem the notes within 45 days
of such public equity offering; and (3) at least 65% of the aggregate
principal amount of the applicable series of notes originally issued under
the applicable indenture, including the principal amount of any additional
notes, remains outstanding immediately after each such redemption.
-117-
(8) The Company may not voluntarily prepay these notes prior to July 15, 2005,
except that the Company may on any one or more occasions make such
prepayment with the proceeds of one or more public equity offerings.
(9) Issued in Canadian dollars.
(10) Issued in Euros.
(11) Issued in Sterling.
(12) The Company may redeem some or all of the notes at any time on or after
October 1, 2009 at specified redemption prices. At any time prior to
October 1, 2009, the Company may redeem some or all of the notes at a price
equal to 100% of their principal amount and the applicable premium plus
accrued and unpaid interest. In addition, at any time prior to October 1,
2007, the Company may redeem up to 35% of the aggregate principal amount of
the notes with the net proceeds from one or more public equity offerings at
a stated redemption price.
</FN>
The Company has completed a series of public debt offerings since 1994.
Interest is payable quarterly or semiannually at specified rates. Deferred
financing costs are amortized using the effective interest method, over the
respective lives of the notes. There are no sinking fund or mandatory
redemptions of principal before the maturity dates of each offering. Certain of
the Senior Note indentures limit the Company's ability to incur additional debt,
pay dividends, sell assets and enter into certain transactions. As of December
31, 2004, the Company was in compliance with all debt covenants relating to the
Senior Notes. The effective interest rates for each of the Company's Senior
Notes outstanding at December 31, 2004, are consistent with the respective notes
outstanding during 2003, unless otherwise noted.
Senior notes repurchased by the Company during 2004 and 2003 totaled $743.4
million and $1,378.5 million, respectively, in aggregate outstanding principal
amount at a repurchase price of $559.3 million and $1,116.5 million,
respectively, plus accrued interest. The Company recorded a pre-tax gain on
these transactions in the amount of $177.6 million and $245.5 million,
respectively, net of write-offs of unamortized deferred financing costs and the
unamortized premiums or discounts. The following table summarizes the total
senior notes repurchased by the Company in the year ended December 31, 2004 and
2003, respectively (in millions):
2004 2003
-------------------- ------------------------
Principal Amount Principal Amount
Debt Security Amount Paid Amount Paid
- -------------------------------- --------- --------- ----------- -----------
8 1/4% Senior Notes Due 2005.... $ 38.9 $ 34.9 $ 25.0 $ 24.5
10 1/2% Senior Notes Due 2006... 13.9 12.4 5.2 5.1
7 5/8% Senior Notes Due 2006.... 103.1 96.5 35.3 32.5
8 3/4% Senior Notes Due 2007.... 30.8 24.4 48.9 45.0
7 7/8% Senior Notes Due 2008.... 78.4 56.5 74.8 58.3
8 1/2% Senior Notes Due 2008(1). 344.3 249.4 48.3 42.3
8 3/8% Senior Notes Due 2008(1). 6.1 4.0 59.2 46.6
7 3/4% Senior Notes Due 2009.... 11.0 8.1 97.2 75.9
8 5/8% Senior Notes Due 2010.... -- -- 210.4 170.7
8 1/2% Senior Notes Due 2011.... 116.9 73.1 648.4 521.3
8 7/8% Senior Notes Due 2011(1). -- -- 125.8 94.3
--------- --------- ----------- -----------
$ 743.4 $ 559.3 $ 1,378.5 $ 1,116.5
========= ========= =========== ===========
- ------------
(1) $395.5 million of such repurchased notes have been pledged as security as
part of the transactions relating to the issuance by Calpine (Jersey)
Limited of Redeemable Preferred Shares. See Note 12 for additional
information on such issuance of Redeemable Preferred Shares.
Additionally, senior notes totaling $80.0 million in principal amount were
exchanged for 11.5 million shares of Calpine common stock in privately
negotiated transactions during 2003. The Company recorded a $17.9 million
pre-tax gain on these transactions, net of write-offs of unamortized deferred
financing costs and the unamortized premiums or discounts. The following table
summarizes the total senior notes exchanged for common stock by the Company in
the year ended December 31, 2003 (in millions):
Principal Common Stock
Debt Security Amount Issued
- ------------------------------------------------------- --------- ------------
8 1/2% Senior Notes Due 2008........................... $ 55.0 8.1
8 1/2% Senior Notes Due 2011........................... 25.0 3.4
------- ---
$ 80.0 1.5
======= ===
-118-
First Priority Senior Secured Notes Due 2014
On September 30, 2004, the Company closed on $785 million of 9 5/8%
First-Priority Senior Secured Notes Due 2014 ("9 5/8% Senior Notes"), offered at
99.212% of par. The 9 5/8% Senior Notes are secured, by substantially all of the
assets owned directly by Calpine Corporation, and by the stock of substantially
all of its first-tier subsidiaries. Net proceeds from the 9 5/8% Senior Notes
offering were used to make open-market purchases of the Company's existing
indebtedness and any remaining proceeds will be applied toward further
open-market purchases (or redemption) of existing indebtedness and as otherwise
permitted by the Company's indentures. The Company may redeem some or all of the
notes at any time on or after October 1, 2009 at specified redemption prices. At
any time prior to October 1, 2009, the Company may redeem some or all of the
notes at a price equal to 100% of their principal amount and the applicable
premium plus accrued and unpaid interest. In addition, at any time prior to
October 1, 2007, the Company may redeem up to 35% of the aggregate principal
amount of the notes with the net proceeds from one or more public equity
offerings at a stated redemption price. Interest is payable on these notes on
April 1 and October 1 of each year, beginning on April 1, 2005. The notes will
mature on September 30, 2014. At December 31, 2004, both the book and face value
of these notes were $779.0 million and $785.0 million, respectively. The
effective interest rate, after amortization of deferred financing costs, was
10.0% per annum at December 31, 2004.
First Priority Senior Secured Term Loan B Notes Due 2007
The Company was to repay these notes in 16 consecutive quarterly
installments, commencing on October 15, 2003, and ending on July 15, 2007, the
first fifteen of which were to be for 0.25% of the original principal amount of
the notes thru April 15, 2007. These notes were redeemable at any time prior to
maturity with certain provisions. These notes were repaid prior to their
maturity with the proceeds from the sale of certain oil and gas properties
during 2004. The effective interest rate, after amortization of deferred
financing costs, was 5.2% and 5.0% per annum at December 31, 2004 and 2003,
respectively.
Second Priority Senior Secured Term Loan B Notes Due 2007
The Company must repay these notes in 16 consecutive quarterly
installments, commencing on October 15, 2003, and ending on July 15, 2007, the
first fifteen of which will be 0.25% of the original principal amount of the
notes thru April 15, 2007. The final installment, on July 15, 2007, will be
96.25% of the original principal amount. Interest is payable on each quarterly
payment date occurring after the closing date of July 16, 2003. The Company may
not voluntarily prepay these notes prior to July 15, 2005, except that the
Company may on any one or more occasions make such prepayment with the proceeds
of one or more public equity offerings. At December 31, 2004, both the book and
face value of these notes was $740.6 million. The effective interest rate, after
amortization of deferred financing costs, was 7.8% and 7.5% per annum at
December 31, 2004 and 2003, respectively.
Second Priority Senior Secured Floating Rate Notes Due 2007
The Company must repay these notes in 16 consecutive quarterly
installments, commencing on October 15, 2003, and ending on July 15, 2007, the
first fifteen of which will be 0.25% of the original principal amount of the
notes thru April 15, 2007. The final installment, on July 15, 2007, will be
96.25% of the original principal amount. On or before July 15, 2005, on one or
more occasions, the Company may use the proceeds from one or more public equity
offerings to redeem up to 35% of the aggregate principal amount of the notes at
the stated redemption price of par plus the applicable Eurodollar rate in effect
at the time of redemption. Interest is payable on each quarterly payment date
occurring after the closing date of July 16, 2003. At December 31, 2004, both
the book and face value of these notes was $493.8 million. The effective
interest rate, after amortization of deferred financing costs, was 7.8% and 7.4%
per annum at December 31, 2004 and 2003, respectively.
Second Priority Senior Secured Notes Due 2010
Interest is payable on these notes on January 15 and July 15 of each year.
The notes will mature on July 15, 2010. On or before July 15, 2006, on one or
more occasions, the Company may use the proceeds from one or more public equity
offerings to redeem up to 35% of the aggregate principal amount of the notes at
the stated redemption price of 108.5%. At December 31, 2003, both the book and
face value of these notes were $1,150.0 million. The effective interest rate,
after amortization of deferred financing costs, was 8.9% and 8.8% per annum at
December 31, 2004 and 2003, respectively.
-119-
Second Priority Senior Secured Notes Due 2011
Interest is payable on these notes on June 1 and December 1 of each year,
commencing on June 1, 2004. The notes will mature on December 1, 2011, and are
not redeemable prior to maturity. At December 31, 2004, the book and face value
of these notes were $393.2 million and $400.0 million, respectively. The
effective interest rate, after amortization of deferred financing costs, was
10.7% and 10.5% per annum at December 31, 2004 and 2003, respectively.
Second Priority Senior Secured Notes Due 2013
Interest is payable on these notes on January 15 and July 15 of each year.
The notes will mature on July 15, 2013. On or before July 15, 2006, on one or
more occasions, the Company may use the proceeds from one or more public equity
offerings to redeem up to 35% of the aggregate principal amount of the notes at
the stated redemption price of 108.75%. At December 31, 2004, both the book and
face value of these notes were $900.0 million. The effective interest rate,
after amortization of deferred financing costs, was 9.0% per annum at December
31, 2004 and 2003.
Senior Notes Due 2005
Interest on the 8 1/4% notes is payable semi-annually on February 15 and
August 15. The notes mature on August 15, 2005, or may be redeemed at any time
prior to maturity at a redemption price equal to 100% of their principal amount
plus accrued and unpaid interest plus a make-whole premium. At December 31,
2004, the book value and face value of these notes were $185.9 million and
$186.1 million, respectively. The effective interest rate, after amortization of
deferred financing costs, is 8.7% per annum.
Senior Notes Due 2006
Interest on the 10 1/2% notes is payable semi-annually on May 15 and
November 15 each year. The notes mature on May 15, 2006, or are redeemable, at
the option of the Company, at any time on or after May 15, 2001, at various
redemption prices. In addition, the Company may redeem up to $63.0 million of
the Senior Notes Due 2006 from the proceeds of any public equity offering. At
December 31, 2004, both the book value and face value of these notes were $152.7
million. The effective interest rate, after amortization of deferred financing
costs, was 11.0% per annum at December 31, 2004, and 10.6% per annum at December
31, 2003.
Interest on the 7 5/8% notes is payable semi-annually on April 15 and
October 15 each year. The notes mature on April 15, 2006, and are not redeemable
prior to maturity. At December 31, 2004, the book value and face value of these
notes were $111.6 million. The effective interest rate, after amortization of
deferred financing costs, was 8.0% and 7.9% per annum at December 31, 2004 and
2003, respectively.
Senior Notes Due 2007
Interest on the 8 3/4% notes maturing on July 15, 2007, is payable
semi-annually on January 15 and July 15 each year. These notes are redeemable,
at the option of the Company, at any time on or after July 15, 2002, at various
redemption prices. In addition, the Company may redeem up to $96.3 million of
the Senior Notes Due 2007 from the proceeds of any public equity offering. At
December 31, 2004, both the book value and face value of these notes were $195.3
million. The effective interest rate, after amortization of deferred financing
costs, was 9.2% and 9.1% per annum at December 31, 2004 and 2003, respectively.
Interest on the 8 3/4% notes maturing on October 15, 2007, is payable
semi-annually on April 15 and October 15 each year. The notes may be redeemed
prior to maturity, at any time in whole or from time to time in part, at a
redemption price equal to the greater of (a) the "Discounted Value" of the
senior notes, which equals the sum of the present values of all remaining
scheduled payments of principal and interest, or (b) 100% of the principal
amount plus accrued and unpaid interest to the redemption date. The notes are
fully and unconditionally guaranteed by the Company. At December 31, 2004, the
book value and face value of these notes were $165.6 million and $166.0 million,
respectively. The effective interest rate, after amortization of deferred
financing costs and the effect of cross currency swaps, was 9.4% at December 31,
2004, and 8.9% at December 31, 2003.
Senior Notes Due 2008
Interest on the 7 7/8% notes is payable semi-annually on April 1 and
October 1 each year. These notes mature on April 1, 2008, and are not redeemable
prior to maturity. At December 31, 2004, the book value and face value of these
notes were $227.1 million and $227.3 million, respectively. The effective
interest rate, after amortization of deferred financing costs, was 8.1% per
annum at December 31, 2004 and 2003. The notes are fully and unconditionally
guaranteed by the Company.
-120-
Interest on the 8 1/2% notes is payable semi-annually on May 1 and November
1 each year. The notes mature on May 1, 2008, or may be redeemed prior to
maturity at a redemption price equal to 100% of the principal amount plus
accrued and unpaid interest plus a make-whole premium. At December 31, 2004, the
book value and face value of these notes were $1,581.5 million and $1,582.4
million, respectively. The effective interest rate, after amortization of
deferred financing costs, was 8.8% per annum at December 31, 2004, and 8.7% per
annum at December 31, 2003.
Interest on the 8 3/8% notes is payable semi- annually on April 15 and
October 15 each year. The notes mature on October 15, 2008, or may be redeemed
prior to maturity at a redemption price equal to 100% of the principal amount
plus accrued and unpaid interest plus a make-whole premium. At December 31,
2004, both the book value and face value of these notes were $160.0 million. The
effective interest rate, after amortization of deferred financing costs and the
effect of cross currency swaps, was 8.6% per annum at December 31, 2004, and
8.7% per annum at December 31, 2003.
Senior Notes Due 2009
Interest on these 7 3/4% notes is payable semi-annually on April 15 and
October 15 each year. The notes mature on April 15, 2009, and are not redeemable
prior to maturity. At December 31, 2003, the book value and face value of these
notes were $221.5 million and $221.6 million, respectively. The effective
interest rate, after amortization of deferred financing costs, was 8.0% per
annum at December 31, 2004 and 2003.
Senior Notes Due 2010
Interest on these 8 5/8% notes is payable semi-annually on August 15 and
February 15 each year. The notes mature on August 15, 2010, and may be redeemed
at any time prior to maturity at a redemption price equal to 100% of their
principal amount plus accrued and unpaid interest plus a make-whole premium. At
December 31, 2004, the book value and face value of these notes were $497.0
million and $497.3 million, respectively. The effective interest rate, after
amortization of deferred financing costs, was 8.8% per annum.
Senior Notes Due 2011
Interest on the 8 1/2% notes is payable semi-annually on February 15 and
August 15 each year. The notes mature on February 15, 2011, and may be redeemed
prior to maturity at a redemption price equal to 100% of the principal amount
plus accrued and unpaid interest plus a make-whole premium. At December 31,
2004, the book value and face value of these notes were $1,063.9 million and
$1,088.6 million, respectively. The effective interest rate, after amortization
of deferred financing costs, was 8.4% and 8.7% per annum at December 31, 2004
and 2003, respectively.
Interest on the 8 7/8% notes is payable semi-annually on April 15 and
October 15 each year. The notes mature on October 15, 2011, and may be redeemed
prior to maturity at a redemption price equal to 100% of the principal amount
plus accrued and unpaid interest plus a make-whole premium. At December 31,
2004, the book value and face value of these notes were $232.5 million and
$233.9 million, respectively. The effective interest rate, after amortization of
deferred financing costs and the effect of cross currency swaps, was 9.3% per
annum at December 31, 2004, and 9.4% per annum at December 31, 2003.
19. Provision for Income Taxes
The jurisdictional components of income (loss) from continuing operations
and before provision for income taxes at December 31, 2004, 2003, and 2002, are
as follows (in thousands):
2004 2003 2002
------------ ------------ ------------
U.S.................................................................................... $ (441,940) $ (113,118) $ (26,875)
International.......................................................................... (248,419) 52,630 51,148
------------ ------------ ------------
Income (loss) before provision for income taxes...................................... $ (690,359) $ (60,488) $ 24,273
============ ============ ============
-121-
The components of the provision (benefit) for income taxes for the years
ended December 31, 2004, 2003, and 2002, consists of the following (in
thousands):
2004 2003 2002
------------ ------------ ------------
Current:
Federal.............................................................................. $ -- $ 350 $ (72,835)
State................................................................................ 1,198 -- 3,837
Foreign.............................................................................. 1,296 -- --
------------ ------------ ------------
Total Current....................................................................... 2,494 350 (68,998)
Deferred:
Federal.............................................................................. (153,103) (51,576) 57,876
State................................................................................ 24,184 (2,932) 11,864
Foreign.............................................................................. (121,265) 19,771 21,140
------------ ------------ ------------
Total Deferred...................................................................... (250,184) (34,737) 90,880
------------ ------------ ------------
Total provision (benefit).......................................................... $ (247,690) $ (34,387) $ 21,882
============ ============ ============
A reconciliation of the Company's overall actual effective tax rate
(benefit) to the statutory U.S. Federal income tax rate of 35% to pretax income
from continuing operations is as follows for the years ended December 31:
2004 2003 2002
------------ ------------ ------------
Expected tax (benefit) rate at United States statutory tax rate........................ (35.00)% (35.00)% 35.00%
State income tax (benefit), net of federal benefit..................................... 2.40% (3.20)% 42.00%
Depletion and other permanent items.................................................... 0.50 1.40% (0.20)%
Valuation allowances................................................................... 1.00% 4.70% --
Tax credits............................................................................ (0.20)% (4.10)% --
Foreign tax at rates other than U.S. statutory rate.................................... (4.60)% (6.70)% 13.30%
Other, net (including U.S. tax on Foreign Income)...................................... -- (13.90)% --
------ ------ -----
Effective income tax (benefit) rate.................................................... (35.90)% (56.80)% 90.10%
====== ====== =====
The components of the deferred income taxes, net as of December 31, 2004
and 2003, are as follows (in thousands):
2004 2003
------------ ------------
Deferred tax assets:
Net operating loss and credit carryforwards.......................................................... $ 1,095,688 $ 450,072
Taxes related to risk management activities and SFAS No. 133......................................... 71,226 76,683
Other differences.................................................................................... 324,040 105,280
------------ ------------
Deferred tax assets before valuation allowance....................................................... 1,490,954 632,035
Valuation allowance.................................................................................. (62,822) (19,335)
------------ ------------
Total Deferred tax assets.......................................................................... 1,428,132 612,700
------------ ------------
Deferred tax liabilities:
Property differences................................................................................. (2,238,278) (1,835,388)
------------ ------------
Total Deferred tax liabilities..................................................................... (2,238,278) (1,835,388)
------------ ------------
Net deferred tax liability........................................................................ (810,146) (1,222,688)
Less: Current portion: asset/(liability)(1)....................................................... (75,608) 15,709
------------- ------------
Deferred income taxes, net of current portion..................................................... $ (885,754) $ (1,206,979)
============ ============
- ------------
<FN>
(1) Current portion of net deferred income taxes are classified within other
current assets in 2004 and other current liabilities in 2003 on the
Consolidated Balance Sheet.
</FN>
-122-
The net operating loss carryforward consists of federal and state
carryforwards of approximately $2.3 billion which expire between 2017 and 2019.
The federal and state net operating loss carryforwards available are subject to
limitations on their annual usage. The Company also has loss carryforwards in
certain foreign subsidiaries, resulting in tax benefits of approximately $152
million, the majority of which expire by 2008. The Company provided a valuation
allowance on certain state and foreign tax jurisdiction deferred tax assets to
reduce the gross amount of these assets to the extent necessary to result in an
amount that is more likely than not of being realized. Realization of the
deferred tax assets and net operating loss carryforwards is dependent, in part,
on generating sufficient taxable income prior to expiration of the loss
carryforwards. The amount of the deferred tax asset considered realizable,
however, could be reduced in the near term if estimates of future taxable income
during the carryforward period are reduced. The Company is under an Internal
Revenue Service review for the years 1999 through 2002 and is periodically under
audit for various state and foreign jurisdictions for income and sales and use
taxes. The Company believes that the ultimate resolution of these examinations
will not have a material effect on its consolidated financial position.
The Company's foreign subsidiaries had no cumulative undistributed earnings
at December 31, 2004.
For the years ended December 31, 2004, 2003 and 2002, the net change in the
valuation allowance was an increase (decrease) of $43.5 million, $(7.3) million
and $26.7 million, respectively, and is primarily related to loss carryforwards
that are not currently realizable.
On October 22, 2004, the American Jobs Creation Act of 2004 was signed into
law. This legislation contains a number of changes to the Internal Revenue Code.
The Company has analyzed the law in order to determine its effects. The two most
notable provisions are those dealing with the reduced tax rate on the
repatriation of money from foreign operations and the deduction for
domestic-based manufacturing activity. The Company determined that it qualifies
for both of these provisions. See Note 10 for further information. Since the
Company is projecting that it will continue to generate net operating losses for
at least the next twelve months it cannot take advantage of the domestic-based
manufacturing deduction at this time.
20. Employee Benefit Plans
Retirement Savings Plan
The Company has a defined contribution savings plan under Section 401(a)
and 501(a) of the Internal Revenue Code. The plan provides for tax deferred
salary deductions and after-tax employee contributions. Employees are
immediately eligible upon hire. Contributions include employee salary deferral
contributions and employer profit-sharing contributions made entirely in cash of
4% of employees' salaries, with employer contributions capped at $8,200 per year
for 2004 and $8,400 per year for 2005. Employer profit-sharing contributions in
2004, 2003, and 2002 totaled $12.8 million, $10.7 million, and $11.6 million,
respectively.
2000 Employee Stock Purchase Plan
The Company adopted the 2000 Employee Stock Purchase Plan ("ESPP") in May
2000. Eligible employees may in the aggregate purchase up to 28,000,000 shares
of common stock at semi-annual intervals through periodic payroll deductions.
Purchases are limited to a maximum value of $25,000 per calendar year based on
the IRS code Section 423 limitation. Shares are purchased on May 31 and November
30 of each year until termination of the plan on May 31, 2010 and limited to
2,400 shares per purchase interval. Under the ESPP, 4,545,858 and 3,636,139
shares were issued at a weighted average fair value of $3.26 and $3.69 per share
in 2004 and 2003, respectively. The purchase price is 85% of the lower of (i)
the fair market value of the common stock on the participant's entry date into
the offering period, or (ii) the fair market value on the semi-annual purchase
date. The purchase price discount is significant enough to cause the ESPP to be
considered compensatory under SFAS No. 123. As a result, the ESPP is accounted
for as stock-based compensation in accordance with SFAS No. 123. See Note 21 for
information related to the Company's stock-based compensation expense.
1996 Stock Incentive Plan
The Company adopted the 1996 Stock Incentive Plan ("SIP") in September
1996. The SIP succeeded the Company's previously adopted stock option program.
Prior to the adoption of SFAS No. 123 prospectively on January 1, 2003, (see
Note 21), the Company accounted for the SIP under APB Opinion No. 25, under
which no compensation cost was recognized through December 31, 2002. See Note 21
for the effects the SIP would have on the Company's financial statements if
stock-based compensation had been accounted for under SFAS No. 123 prior to
January 1, 2003.
-123-
For the year ended December 31, 2004, the Company granted options to
purchase 5,660,262 shares of common stock. Over the life of the SIP, options
exercised have equaled 5,088,290, leaving 32,937,993 granted and not yet
exercised. Under the SIP, the option exercise price generally equals the stock's
fair market value on date of grant. The SIP options generally vest ratably over
four years and expire after 10 years.
In connection with the merger with Encal in 2001, the Company adopted
Encal's existing stock option plan. All outstanding options under the Encal
stock option plan were converted at the time of the merger into options to
purchase Calpine stock. No new options may be granted under the Encal stock
option plan. As of December 31, 2004, there were 87,274 and 1,752,590 options
granted and not yet exercised under the Encal and Calpine's 1992 stock option
plans, respectively.
Changes in options outstanding, granted, exercisable and canceled during
the years 2004, 2003, and 2002, under the option plans of Calpine and Encal were
as follows:
Weighted
Available for Outstanding Average
Option or Number of Exercise
Award Options Price
------------- ----------- --------
Outstanding January 1, 2002............................................................ 2,855,949 27,690,564 $ 9.32
----------- ---------- ---------
Additional shares reserved........................................................... 15,070,588
Granted............................................................................. (8,997,720) 8,997,720 7.20
Exercised........................................................................... -- (5,112,535) 0.77
Canceled............................................................................ 1,470,802 (1,470,802) 26.53
Canceled options(1)................................................................. (237,705) -- --
----------- ---------- ---------
Outstanding December 31, 2002.......................................................... 10,161,914 30,104,947 $ 9.30
----------- ---------- ---------
Granted.............................................................................. (5,998,585) 5,998,585 3.93
Exercised............................................................................ -- (536,730) 2.01
Canceled............................................................................. 1,725,221 (1,725,221) 13.59
Canceled options(1).................................................................. (72,470)
Awards issued........................................................................ -- (3,150) 4.03
----------- ---------- ---------
Outstanding December 31, 2003.......................................................... 5,816,080 33,838,431 $ 8.25
----------- ---------- ---------
Additional shares reserved........................................................... 21,000,000 -- --
Granted............................................................................. (5,660,262) 5,660,262 5.47
Exercised........................................................................... -- (3,629,824) 0.83
Canceled............................................................................ 1,089,032 (1,089,032) 18.21
Canceled options(1)................................................................. (38,945) -- --
Awards issued....................................................................... -- (1,980) 4.33
----------- ---------- ---------
Outstanding December 31, 2004.......................................................... 22,205,905 34,777,857 8.42
----------- ---------- ---------
Options exercisable:
December 31, 2002.................................................................... 19,418,239 7.14
December 31, 2003.................................................................... 22,953,781 8.02
December 31, 2004.................................................................... 22,949,497 9.30
- ------------
<FN>
(1) Represents cessation of options awarded under the Encal stock option plan
</FN>
The following tables summarizes information concerning outstanding and
exercisable options at December 31, 2004:
Weighted
Average Weighted Weighted
Number of Remaining Average Number of Average
Range of Options Contractual Exercise Options Exercise
Exercise Prices Outstanding Life in Years Price Exercisable Price
- ------------------ ----------- ------------- -------- ------------ --------
$ 0.645-$ 2.150... 4,073,196 2.55 $ 1.606 4,072,693 $ 1.606
$ 2.240-$ 3.860... 5,220,014 3.58 3.321 5,166,889 3.321
$ 3.910-$ 3.980... 5,254,837 8.02 3.980 1,720,183 3.980
$ 4.010-$ 5.240... 3,036,785 7.36 5.157 1,691,122 5.094
$ 5.250-$ 5.560... 5,397,275 9.15 5.560 152,350 5.549
$ 5.565-$ 7.640... 3,854,747 5.97 7.561 2,847,889 7.538
$ 7.750-$13.850... 3,735,013 4.86 10.595 3,465,918 10.343
$13.917-$48.150... 4,063,810 5.00 31.054 3,705,184 29.569
$48.188-$56.920... 140,330 6.23 51.292 125,419 51.271
$56.990-$56.990... 1,850 6.33 56.990 1,850 56.990
---------- ----------
$ 0.645-$56.990... 34,777,857 5.90 $ 8.416 22,949,497 $ 9.299
========== ==========
-124-
21. Stockholders' Equity
Common Stock
Increase in Authorized Shares -- On June 2, 2004, the Company filed amended
certificates with the Delaware Secretary of State to increase the number of
authorized shares of common stock to 2,000,000,000 from 1,000,000,000.
Equity Offerings -- On April 30, 2002, Calpine completed a registered
offering of 66,000,000 shares of common stock at $11.50 per share. The proceeds
from this offering, after underwriting fees, were $734.3 million.
On September 30, 2004, in conjunction with the 2014 Convertible Notes
offering (see Note 17 for more information regarding this offering), the Company
entered into a ten-year Share Lending Agreement with Deutsche Bank AG London
("DB London"), under which the Company loaned DB London 89 million shares of
newly issued Calpine common stock in exchange for a loan fee of $0.001 per
share. DB London sold the 89 million shares on September 30, 2004 at a price of
$2.75 per share in a registered public offering. The Company did not receive any
of the proceeds of the public offering. As discussed in Note 17, the requirement
to return these shares is considered to be a prepaid forward purchase contract
and the Company analogizes to the guidance in SFAS No. 150 so that the 89
million shares of common stock subject to the Share Lending Agreement are
excluded from the EPS calculation.
Preferred Stock and Preferred Share Purchase Rights
On June 5, 1997, Calpine adopted a stockholders' rights plan to strengthen
Calpine's ability to protect Calpine's stockholders. The plan was amended on
September 19, 2001, and further amended on September 28, 2004 and March 18,
2005. The rights plan was designed to protect against abusive or coercive
takeover tactics that are not in the best interests of Calpine or its
stockholders. To implement the rights plan, Calpine declared a dividend of one
preferred share purchase right for each outstanding share of Calpine's common
stock held on record as of June 18, 1997, and directed the issuance of one
preferred share purchase right with respect to each share of Calpine's common
stock that shall become outstanding thereafter until the rights become
exercisable or they expire as described below. On December 31, 2004, there were
536,509,231 rights outstanding. Each right initially represents a contingent
right to purchase, under certain circumstances, one one-thousandth of a share,
called a "unit," of Calpine's Series A Participating Preferred Stock, par value
$.001 per share, at a price of $140.00 per unit, subject to adjustment. The
rights become exercisable and trade independently from Calpine's common stock
upon the public announcement of the acquisition by a person or group of 15% or
more of Calpine's common stock, or ten days after commencement of a tender or
exchange offer that would result in the acquisition of 15% or more of Calpine's
common stock. Each unit purchased upon exercise of the rights will be entitled
to a dividend equal to any dividend declared per share of common stock and will
have one vote, voting together with the common stock. In the event of Calpine's
liquidation, each share of the participating preferred stock will be entitled to
any payment made per share of common stock.
If Calpine is acquired in a merger or other business combination
transaction after a person or group has acquired 15% or more of Calpine's common
stock, each right will entitle its holder to purchase at the right's exercise
price a number of the acquiring company's shares of common stock having a market
value of twice the right's exercise price. In addition, if a person or group
acquires 15% or more of Calpine's common stock, each right will entitle its
holder (other than the acquiring person or group) to purchase, at the right's
exercise price, a number of fractional shares of Calpine's participating
preferred stock or shares of Calpine's common stock having a market value of
twice the right's exercise price.
The rights remain exercisable for up to 90 days following a triggering
event (such as a person acquiring 15% or more of the Company's common Stock).
The rights expire on May 1, 2005, unless redeemed earlier by Calpine. Calpine
can redeem the rights at a price of $.01 per right at any time before the rights
become exercisable, and thereafter only in limited circumstances.
Stock-Based Compensation
On January 1, 2003, the Company prospectively adopted the fair value method
of accounting for stock-based employee compensation pursuant to SFAS No. 123 as
amended by SFAS No. 148. SFAS No. 148 amends SFAS No. 123 to provide alternative
methods of transition for companies that voluntarily change their accounting for
stock-based compensation from the less preferred intrinsic value based method to
the more preferred fair value based method. Prior to its amendment, SFAS No. 123
required that companies enacting a voluntary change in accounting principle from
the intrinsic value methodology provided by APB Opinion No. 25 could only do so
on a prospective basis; no adoption or transition provisions were established to
allow for a restatement of prior period financial statements. SFAS No. 148
provides two additional transition options to report the change in accounting
principle -- the modified prospective method and the retroactive restatement
-125-
method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS
No. 123 to require prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results. The Company elected to
adopt the provisions of SFAS No. 123 on a prospective basis; consequently, the
Company is required to provide a pro-forma disclosure of net income and EPS as
if SFAS No. 123 accounting had been applied to all prior periods presented
within its financial statements. As shown below, the adoption of SFAS No. 123
has had a material impact on the Company's financial statements. The table below
reflects the pro forma impact of stock-based compensation on the Company's net
income (loss) and earnings (loss) per share for the years ended December 31,
2004, 2003 and 2002, had the Company applied the accounting provisions of SFAS
No. 123 to its financial statements in years prior to adoption of SFAS No. 123
on January 1, 2003 (in thousands, except per share amounts):
2004 2003 2002
------------ ------------ ------------
Net income (loss)
As reported......................................................................... $ (242,461) $ 282,022 $ 118,618
Pro Forma........................................................................... (247,316) 270,418 83,025
Earnings (loss) per share data:
Basic earnings (loss) per share
As reported......................................................................... $ (0.56) $ 0.72 $ 0.33
Pro Forma........................................................................... (0.57) 0.69 0.23
Diluted earnings per share
As reported......................................................................... $ (0.56) $ 0.71 $ 0.33
Pro Forma........................................................................... (0.57) 0.68 0.23
Stock-based compensation cost included in net income (loss), as reported............... $ 12,734 $ 9,724 $ --
Stock-based compensation cost included in net income (loss), pro forma................. 17,589 21,328 35,593
The range of fair values of the Company's stock options granted in 2004,
2003, and 2002 were as follows, based on varying historical stock option
exercise patterns by different levels of Calpine employees: $1.83-$4.45 in 2004,
$1.50-$4.38 in 2003 and $3.73-$6.62 in 2002 on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions: expected dividend yields of 0%, expected volatility of 69%-98% for
2004, 70%-113% for 2003 and 70%-83% for 2002, risk-free interest rates of 2.35%-
4.54% for 2004, 1.39%-4.04% for 2003 and 2.39%-3.83% for 2002, and expected
option terms of 3-9.5 years for 2004, 1.5-9.5 years for 2003 and 4-9 years for
2002.
In December 2004, FASB issued SFAS No. 123-R. This Statement revises SFAS
No. 123 and supersedes APB Opinion No. 25, and its related implementation
guidance. See Note 2 for further information.
Comprehensive Income (Loss)
-126-
Comprehensive income is the total of net income and all other non-owner
changes in equity. Comprehensive income includes the Company's net income,
unrealized gains and losses from derivative instruments that qualify as cash
flow hedges, unrealized gains and losses from available-for-sale securities
which are marked to market, the Company's share of its equity method investee's
OCI, and the effects of foreign currency translation adjustments. The Company
reports Accumulated Other Comprehensive Income ("AOCI") in its Consolidated
Balance Sheet. The tables below detail the changes during 2004, 2003 and 2002 in
the Company's AOCI balance and the components of the Company's comprehensive
income (in thousands):
Total
Accumulated
Available- Foreign Other
Cash Flow For-Sale Currency Comprehensive Comprehensive
Hedges(1) Investments Translation Income (Loss) Income (Loss)
--------- ----------- ----------- ------------- -------------
Accumulated other comprehensive loss at January 1, 2002..... $(180,819) $ -- $ (60,061) $ (240,880)
--------- ----------- ----------- ------------
Net income.................................................. $ 118,618
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedgese
before reclassification adjustment...................... 96,905
Reclassification adjustment for gain included in
net income.............................................. (169,205)
Income tax benefit....................................... 28,705
---------
(43,595) (43,595) (43,595)
Foreign currency translation gain......................... 47,018 47,018 47,018
--------- ----------- ------------- -------------
Total comprehensive income.................................. $ 122,041
=============
Accumulated other comprehensive loss at
December 31, 2002......................................... $(224,414) $ (13,043) $ (237,457)
========= =========== =============
Net income.................................................. $ 282,022
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges
before reclassification adjustment...................... 112,481
Reclassification adjustment for loss included in
net income.............................................. 55,620
Income tax provision..................................... (74,106)
---------
93,995 93,995 93,995
Foreign currency translation gain......................... 200,056 200,056 200,056
--------- ----------- ------------- -------------
Total comprehensive income.................................. $ 576,073
=============
Accumulated other comprehensive gain (loss) at
December 31, 2003......................................... $(130,419) $ 187,013 $ 56,594
========= =========== ============
Net loss.................................................... $ (242,461)
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
before reclassification adjustment...................... (106,071)
Reclassification adjustment for loss included in
net loss................................................ 89,888
Income tax provision..................................... 6,451
---------
(9,732) (9,732) (9,732)
Available-for-sale investments:
Comprehensive pre-tax gain on available-for-sale
investments before reclassification adjustment........... 19,239
Reclassification adjustment for gain included in
net loss................................................. (18,281)
Income tax provision...................................... (376)
-----------
582 582 582
Foreign currency translation gain........................... 62,067 62,067 62,067
----------- ------------- -------------
Total comprehensive loss.................................... $ (189,544)
============
Accumulated other comprehensive gain (loss) at
December 31, 2004......................................... $(140,151) $ 582 $ 249,080 $ 109,511
========= =========== =========== ============
- ------------
<FN>
(1) Includes AOCI from cash flow hedges held by unconsolidated investees. At
December 31, 2004, 2003 and 2002, these amounts were $1,698, $6,911 and
$12,018, respectively.
</FN>
-127-
22. Customers
Significant Customer
In 2004, 2003 and 2002, Calpine had one significant customer that accounted
for more than 10% of the Company's annual consolidated revenues: the CDWR. See
below for a discussion of the Company's contracts with CDWR.
For the years ended December 31, 2004, 2003, and 2002, CDWR revenues were
$1,148.0 million, $1,219.7 million and $754.2 million, respectively.
Calpine's receivables from CDWR at December 31, 2004, 2003 and 2002, were
$98.5 million, $97.8 million and $78.8 million, respectively.
Counterparty Exposure
The Company's customer and supplier base is concentrated within the energy
industry. Additionally, the Company has exposure to trends within the energy
industry, including declines in the creditworthiness of its marketing
counterparties. Currently, certain companies within the energy industry are in
bankruptcy or have below investment grade credit ratings. However, we do not
currently have any significant exposure to counterparties that are not paying on
a current basis.
California Department of Water Resources
In 2001, California adopted legislation permitting it to issue long-term
revenue bonds to fund wholesale purchases of power by the CDWR. The bonds will
be repaid with the proceeds of payments by retail power customers over time. CES
and CDWR entered into four long-term supply contracts during 2001. The Company
has recorded deferred revenue in connection with one of the long-term power
supply contracts ("Contract 3"). All of the Company's accounts receivables from
CDWR are current, with the exception of approximately $1.0 million which the
Company is working to resolve with the customer.
In early 2002, the CPUC and the California Electricity Oversight Board
("EOB") filed complaints under Section 206 of the Federal Power Act with the
Federal Energy Regulatory Commission ("FERC") alleging that the prices and terms
of the long-term contracts with CDWR were unjust and unreasonable and contrary
to the public interest (the "206 Complaint"). The contracts entered into by CES
and CDWR were subject to the 206 Complaint.
On April 22, 2002, the Company announced that it had renegotiated CES's
long-term power contracts with CDWR and settled the 206 Complaint. The Office of
the Governor, the CPUC, the EOB and the Attorney General for the State of
California all endorsed the renegotiated contracts and dropped all pending
claims against the Company and its affiliates, including any efforts by the CPUC
and the EOB to seek refunds from the Company and its affiliates through the FERC
California Refund Proceedings. In connection with the renegotiation, the Company
agreed to pay $6 million over three years to the Attorney General to resolve any
and all possible claims.
Lease Income
The Company records income under power purchase agreements that are
accounted for as operating leases under SFAS No. 13 and EITF Issue No. 01-08.
For income statement presentation purposes, this income is classified within
electricity and steam revenue in the Consolidated Statements of Operations.
The total contractual future minimum lease payments for these power purchase
agreements are as follows (in thousands):
2005............................................................. $ 123,435
2006............................................................. 175,349
2007............................................................. 213,431
2008............................................................. 285,386
2009............................................................. 288,516
Thereafter....................................................... 2,844,717
-------------
Total.......................................................... $ 3,930,834
=============
The contingent income for these agreements related to our Canadian power
generation asset was $20.1 million, $25.3 million and $28.7 million for the
respective periods, while contingent income under the other power purchase
agreements were collectively immaterial. Property leased to customers under
operating leases is recorded at cost and is depreciated on the straight line
basis to its estimated residual value. Estimated useful lives are 35 years. As
of December 31, 2004, the cost of the leased property was $1,409.6 million and
the accumulated depreciation was $55.6 million. These power purchase agreements
expire over the next 27 years.
-128-
Credit Evaluations
The Company's treasury department includes a credit group focused on
monitoring and managing counterparty risk. The credit group monitors the net
exposure with each counterparty on a daily basis. The analysis is performed on a
mark-to-market basis using the forward curves analyzed by the Company's Risk
Controls group. The net exposure is compared against a counterparty credit risk
threshold which is determined based on each counterparty's credit rating and
evaluation of the financial statements. The credit department monitors these
thresholds to determine the need for additional collateral or restriction of
activity with the counterparty.
23. Derivative Instruments
Commodity Derivative Instruments
As an independent power producer primarily focused on generation of
electricity using gas-fired turbines, the Company's natural physical commodity
position is "short" fuel (i.e., natural gas consumer) and "long" power (i.e.,
electricity seller). To manage forward exposure to price fluctuation in these
and (to a lesser extent) other commodities, the Company enters into derivative
commodity instruments. The Company enters into commodity instruments to convert
floating or indexed electricity and gas (and to a lesser extent oil and refined
product) prices to fixed prices in order to lessen its vulnerability to
reductions in electric prices for the electricity it generates, and to increases
in gas prices for the fuel it consumes in its power plants. The hedging,
balancing, or optimization activities that the Company engages in are directly
related to the Company's asset-based business model of owning and operating
gas-fired electric power plants and are designed to protect the Company's "spark
spread" (the difference between the Company's fuel cost and the revenue it
receives for its electric generation). The Company hedges exposures that arise
from the ownership and operation of power plants and related sales of
electricity and purchases of natural gas. The Company also utilizes derivatives
to optimize the returns it is able to achieve from these assets. From time to
time the Company has entered into contracts considered energy trading contracts
under EITF Issue No. 02-03. However, the Company's traders have low capital at
risk and value at risk limits for energy trading, and its risk management policy
limits, at any given time, its net sales of power to its generation capacity and
limits its net purchases of gas to its fuel consumption requirements on a total
portfolio basis. This model is markedly different from that of companies that
engage in significant commodity trading operations that are unrelated to
underlying physical assets. Derivative commodity instruments are accounted for
under the requirements of SFAS No. 133.
The Company also routinely enters into physical commodity contracts for
sales of its generated electricity to ensure favorable utilization of generation
assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives
but are generally eligible for the normal purchases and sales exception. Some of
those contracts that are not deemed normal purchases and sales can be designated
as hedges of the underlying consumption of gas or production of electricity.
Interest Rate and Currency Derivative Instruments
The Company also enters into various interest rate swap agreements to hedge
against changes in floating interest rates on certain of its project financing
facilities and to adjust the mix between fixed and floating rate debt in its
capital structure to desired levels. Certain of the interest rate swap
agreements effectively convert floating rates into fixed rates so that the
Company can predict with greater assurance what its future interest costs will
be and protect itself against increases in floating rates.
In conjunction with its capital markets activities, the Company enters into
various forward interest rate agreements to hedge against interest rate
fluctuations that may occur after the Company has decided to issue long-term
fixed rate debt but before the debt is actually issued. The forward interest
rate agreements effectively prevent the interest rates on anticipated future
long-term debt from increasing beyond a certain level, allowing the Company to
predict with greater assurance what its future interest costs on fixed rate
long-term debt will be.
Also, in conjunction with its capital market activities, the Company enters
into various interest rate swap agreements to hedge against the change in fair
value on certain of its fixed rate Senior Notes. These interest rate swap
agreements effectively convert fixed rates into floating rates so that the
Company can predict with greater assurance what the fair value of its fixed rate
Senior Notes will be and protect itself against unfavorable future fair value
movements.
-129-
The Company enters into various foreign currency swap agreements to hedge
against changes in exchange rates on certain of its senior notes denominated in
currencies other than the U.S. dollar. The foreign currency swaps effectively
convert floating exchange rates into fixed exchange rates so that the Company
can predict with greater assurance what its U.S. dollar cost will be for
purchasing foreign currencies to satisfy the interest and principal payments on
these senior notes.
Summary of Derivative Values
The table below reflects the amounts (in thousands) that are recorded as
assets and liabilities at December 31, 2004, for the Company's derivative
instruments:
Commodity
Interest Rate Derivative Total
Derivative Instruments Derivative
Instruments Net Instruments
------------- ----------- -----------
Current derivative assets ........................................ $ 620 $323,586 $324,206
Long-term derivative assets ...................................... -- 506,050 506,050
-------- -------- --------
Total assets ................................................... $ 620 $829,636 $830,256
======== ======== ========
Current derivative liabilities ................................... $ 21,578 $334,452 $356,030
Long-term derivative liabilities ................................. 58,909 457,321 516,230
-------- -------- --------
Total liabilities .............................................. $ 80,487 $791,773 $872,260
======== ======== ========
Net derivative assets (liabilities) ........................... $(79,867) $ 37,863 $(42,004)
======== ======== ========
Of the Company's net derivative assets, $289.9 million and $55.4 million
are net derivative assets of PCF and CNEM, respectively, each of which is an
entity with its existence separate from the Company and other subsidiaries of
the Company. The Company fully consolidates CNEM and, as discussed more fully in
Note 2, the Company records the derivative assets of PCF in its balance sheet.
At any point in time, it is highly unlikely that total net derivative
assets and liabilities will equal AOCI, net of tax from derivatives, for three
primary reasons:
o Tax effect of OCI -- When the values and subsequent changes in values
of derivatives that qualify as effective hedges are recorded into OCI,
they are initially offset by a derivative asset or liability. Once in
OCI, however, these values are tax effected against a deferred tax
liability or asset account, thereby creating an imbalance between net
OCI and net derivative assets and liabilities.
o Derivatives not designated as cash flow hedges and hedge
ineffectiveness -- Only derivatives that qualify as effective cash
flow hedges will have an offsetting amount recorded in OCI.
Derivatives not designated as cash flow hedges and the ineffective
portion of derivatives designated as cash flow hedges will be recorded
into earnings instead of OCI, creating a difference between net
derivative assets and liabilities and pre-tax OCI from derivatives.
o Termination of effective cash flow hedges prior to maturity --
Following the termination of a cash flow hedge, changes in the
derivative asset or liability are no longer recorded to OCI. At this
point, an AOCI balance remains that is not recognized in earnings
until the forecasted initially hedged transactions occur. As a result,
there will be a temporary difference between OCI and derivative assets
and liabilities on the books until the remaining OCI balance is
recognized in earnings.
-130-
Below is a reconciliation of the Company's net derivative liabilities to
its accumulated other comprehensive loss, net of tax from derivative instruments
at December 31, 2004 (in thousands):
Net derivative liabilities......................................................................................... $ (42,004)
Net derivative liability reclassified to held for sale............................................................. (19,303)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness................................ (86,496)
Cash flow hedges terminated prior to maturity...................................................................... (75,725)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges........................ 77,640
AOCI from unconsolidated investees................................................................................. 5,737
------------
Accumulated other comprehensive loss from derivative instruments, net of tax(1).................................... $ (140,151)
============
- ------------
<FN>
(1) Amount represents one portion of the Company's total AOCI balance. See Note
21 for further information.
</FN>
The asset and liability balances for the Company's commodity derivative
instruments represent the net totals after offsetting certain assets against
certain liabilities under the criteria of FIN 39. For a given contract, FIN 39
will allow the offsetting of assets against liabilities so long as four criteria
are met: (1) each of the two parties under contract owes the other determinable
amounts; (2) the party reporting under the offset method has the right to set
off the amount it owes against the amount owed to it by the other party; (3) the
party reporting under the offset method intends to exercise its right to set
off; and; (4) the right of set-off is enforceable by law. The table below
reflects both the amounts (in thousands) recorded as assets and liabilities by
the Company and the amounts that would have been recorded had the Company's
commodity derivative instrument contracts not qualified for offsetting as of
December 31, 2004.
December 31, 2004
--------------------------
Gross Net
------------- -----------
Current derivative assets........................... $ 837,196 $ 323,586
Long-term derivative assets......................... 964,825 506,050
------------- -----------
Total derivative assets........................... $ 1,802,021 $ 829,636
============= ===========
Current derivative liabilities...................... $ 848,061 $ 334,452
Long-term derivative liabilities.................... 916,097 457,321
------------- -----------
Total derivative liabilities...................... $ 1,764,158 $ 791,773
============= ===========
Net commodity derivative assets.................. $ 37,863 $ 37,863
============= ===========
The table above excludes the value of interest rate and currency derivative
instruments.
The tables below reflect the impact of unrealized mark-to-market gains
(losses) on the Company's pre-tax earnings, both from cash flow hedge
ineffectiveness and from the changes in market value of derivatives not
designated as hedges of cash flows, for the years ended December 31, 2004, 2003
and 2002, respectively (in thousands):
2004
------------------------------------------
Hedge Undesignated
Ineffectiveness Derivatives Total
--------------- ------------ ---------
Natural gas derivatives(1) ........ $ 5,827 $ (10,700) $ (4,873)
Power derivatives(1) .............. 1,814 (31,666) (29,852)
Interest rate derivatives(2) ...... 1,492 6,035 7,527
Currency derivatives .............. -- (12,897) (12,897)
-------- --------- ---------
Total ............................ $ 9,133 $ (49,228) $ (40,095)
======== ========= =========
-131-
2003
------------------------------------------
Hedge Undesignated
Ineffectiveness Derivatives Total
--------------- ------------ ---------
Natural gas derivatives(1)......... $ 3,153 $ 7,768 $ 10,921
Power derivatives(1)............... (5,001) (56,693) (61,694)
Interest rate derivatives(2)....... (974) -- (974)
Currency derivatives............... -- -- --
-------- --------- ---------
Total $ (2,822) $ (48,925) $ (51,747)
======== ========= =========
2002
------------------------------------------
Hedge Undesignated
Ineffectiveness Derivatives Total
--------------- ------------ ---------
Natural gas derivatives(1)......... $ 2,147 $ (14,792) $ (12,645)
Power derivatives(1)............... (4,934) 12,974 8,040
Interest rate derivatives(2)....... (810) -- (810)
Currency derivatives............... -- -- --
-------- --------- ---------
$ (3,597) $ (1,818) $ (5,415)
======== ========= =========
- ------------
(1) Represents the unrealized portion of mark-to-market activity on gas and
power transactions. The unrealized portion of mark-to-market activity is
combined with the realized portions of mark-to-market activity and
presented in the Consolidated Statements of Operations as mark-to-market
activities, net.
(2) Recorded within Other Income
The table below reflects the contribution of the Company's cash flow hedge
activity to pre-tax earnings based on the reclassification adjustment from OCI
to earnings for the years ended December 31, 2004, 2003 and 2002, respectively
(in thousands):
2004 2003 2002
---------- ---------- ----------
Natural gas and crude oil derivatives.... $ 58,308 $ 40,752 $ (119,419)
Power derivatives........................ (128,556) (79,233) 304,073
Interest rate derivatives................ (17,625) (27,727) (10,993)
Foreign currency derivatives............. (2,015) 10,588 (4,456)
--------- ---------- ----------
Total derivatives...................... $ (89,888) $ (55,620) $ 169,205
========= ========== ==========
This table includes $8.0 million of pre-tax gain which was reclassified to
discontinued operations.
As of December 31, 2004, the maximum length of time over which the Company
was hedging its exposure to the variability in future cash flows for forecasted
transactions was 7 and 12 years, for commodity and interest rate derivative
instruments, respectively. The Company estimates that pre-tax losses of $148.0
million would be reclassified from AOCI into earnings during the twelve months
ended December 31, 2005, as the hedged transactions affect earnings assuming
constant gas and power prices, interest rates, and exchange rates over time;
however, the actual amounts that will be reclassified will likely vary based on
the probability that gas and power prices as well as interest rates and exchange
rates will, in fact, change. Therefore, management is unable to predict what the
actual reclassification from OCI to earnings (positive or negative) will be for
the next twelve months.
The table below presents (in thousands) the pre-tax gains (losses)
currently held in OCI that will be recognized annually into earnings, assuming
constant gas and power prices, interest rates, and exchange rates over time.
2010 &
2005 2006 2007 2008 2009 After Total
---------- ---------- ---------- ---------- ---------- ---------- ----------
Gas OCI .......................... $ (29,476) $ 55,612 $ 1,111 $ 702 $ 343 $ 250 $ 28,542
Power OCI ........................ (98,724) (70,252) (3,854) (589) (343) (94) (173,856)
Interest rate OCI ................ (17,745) (10,960) (7,941) (5,170) (4,126) (20,855) (66,797)
Foreign currency OCI ............. (2,014) (2,014) (1,624) (28) -- -- (5,680)
--------- --------- --------- --------- --------- --------- ---------
Total pre-tax OCI ............... $(147,959) $ (27,614) $ (12,308) $ (5,085) $ (4,126) $ (20,699) $(217,791)
========= ========= ========= ========= ========= ========= =========
-132-
24. Earnings per Share
Basic earnings (loss) per common share were computed by dividing net income
(loss) by the weighted average number of common shares outstanding for the
respective periods. 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 calculation of basic and diluted earnings (loss) per common
share is shown in the following table (in thousands, except per share data).
For the Years Ended December 31,
-----------------------------------------------------------------------------------------
2004 2003 2002
----------------------------- ---------------------------- ----------------------------
Net Net Net
Income Shares EPS Income Shares EPS Income Shares EPS
--------- -------- ------- --------- -------- ------- --------- -------- -------
Basic earnings (loss) per common share:
Income (loss) before discontinued
operations and cumulative effect of
a change in accounting principle...... $(442,669) 430,775 $ (1.03) $ (26,101) 390,772 $ (0.07) $ 2,391 354,822 $ 0.01
Discontinued operations, net of tax.... 200,208 -- 0.47 127,180 -- 0.33 116,227 -- 0.32
Cumulative effect of a change in
accounting principle, net of tax...... -- -- -- 180,943 -- 0.46 -- -- --
--------- -------- ------- --------- -------- ------- --------- -------- ------
Net income............................. $(242,461) 430,775 $ (0.56) $ 282,022 390,772 $ 0.72 $ 118,618 354,822 $ 0.33
========= ======== ======= ========= ======== ======= ========= ======== ======
Diluted earnings per common share:
Common shares issuable upon exercise
of stock options using treasury
stock method.......................... -- 5,447 7,711
Income before dilutive effect of
certain convertible securities,
discontinued operations and
cumulative effect of a change in
accounting principle.................. $(442,669) 430,775 $ (1.03) $ (26,101) 396,219 $ (0.07) $ 2,391 362,533 $ 0.01
Dilutive effect of certain
convertible securities................ -- -- -- -- -- -- -- -- --
--------- ------- ------- --------- -------- ------- --------- -------- -------
Income before discontinued operations
and cumulative effect of a change
in accounting principle............... (442,669) 430,775 (1.03) (26,101) 396,219 (0.07) 2,391 362,533 0.01
Discontinued operations, net of tax.... 200,208 -- 0.47 127,180 -- 0.33 116,227 -- 0.32
Cumulative effect of a change in
accounting principle, net of tax...... -- -- -- 180,943 -- 0.45 -- -- --
--------- -------- ------- --------- -------- ------- --------- -------- -------
Net income............................. $(242,461) 430,775 $ (0.56) $ 282,022 396,219 $ 0.71 $ 118,618 362,533 $ 0.33
========= ======== ======= ========= ======== ======= ========= ======== =======
The Company incurred losses before discontinued operations and cumulative
effect of a change in accounting principle for the year ended December 31, 2004.
As a result, basic shares were used in the calculations of fully diluted loss
per share for these periods, under the guidelines of SFAS No. 128 as using the
basic shares produced the more dilutive effect on the loss per share.
Potentially convertible securities, shares to be purchased under the Company's
ESPP and unexercised employee stock options to purchase a weighted average of
47.2 million, 127.1 million and 136.7 million shares of the Company's common
stock were not included in the computation of diluted shares outstanding during
the years ended December 31, 2004, 2003 and 2002, respectively, because such
inclusion would be antidilutive.
For the years ended December 31, 2004, 2003 and 2002, approximately 8.9
million, 61.0 million and 66.4 million, respectively, weighted common shares of
the Company's outstanding 2006 Convertible Senior Notes were excluded from the
diluted EPS calculations as the inclusion of such shares would have been
antidilutive. See Note 17 for a further discussion of these convertible
securities.
In connection with the convertible notes payable to Trust I, Trust II and
Trust III, net of repurchases, there were 34.4 million, 44.1 million and 44.9
million weighted average common shares potentially issuable, respectively, that
were excluded from the diluted EPS calculation for the years ended December 31,
2004, 2003 and 2002 as their inclusion would be antidilutive. See Note 12 for a
further discussion of these securities.
-133-
For the years ended December 31, 2004 and 2003, under the new guidance of
EITF 04-08 there were no shares potentially issuable and thus potentially
included in the diluted EPS calculation under the Company's 2023 Convertible
Senior Notes issued in November 2003, because the Company's closing stock price
at each period end was below the conversion price. However, in future reporting
periods where the Company's closing stock price is above $6.50, and depending on
the closing stock price at conversion, the maximum potential shares issuable
under the conversion provisions of the 2023 Convertible Senior Notes and
included (if dilutive) in the diluted EPS calculation is approximately 97.5
million shares. See Note 17 for a further discussion of these convertible
securities.
For the year ended December 31, 2004, under the new guidance of EITF 04-08
approximately 8.6 million weighted common shares potentially issuable under the
Company's outstanding 2014 Convertible Notes were excluded from the diluted
earnings per share calculations as the inclusion of such shares would have been
antidilutive because of the Company's net loss. However, in future reporting
periods where the Company's has net income and closing stock price is above
$3.85, and depending on the closing stock price at conversion, the maximum
potential shares issuable under the conversion provisions of the 2014
Convertible Notes and included in the diluted EPS calculation is approximately
191.2 million shares. See Note 17 for a further discussion of these convertible
securities.
As discussed in Note 17, the Company has excluded the 89 million shares of
common stock subject to the Share Lending Agreement from the EPS calculation.
See Note 2 for a discussion of the potential impact of SFAS No. 128-R on
the calculation of diluted EPS.
25. Commitments and Contingencies
Turbines -- On February 11, 2003, the Company announced a significant
restructuring of its turbine agreements, which enabled the Company to cancel up
to 131 steam and gas turbines. The Company recorded a pre-tax charge of $207.4
million in the quarter ending December 31, 2002, in connection with fees paid to
vendors to restructure these contracts. This charge was recorded in the
Equipment cancellation and impairment costs line item on the Consolidated
Statements of Operations in the year ended December 31, 2002. As of December 31,
2004, 91 of these turbines had been cancelled and 2 had been applied to Calpine
projects, leaving the disposition of 38 turbines still to be determined. The
following table sets forth an analysis of the components of the turbine
restructuring charges recorded in the fourth quarter of fiscal 2002 (in
thousands):
Three Months Ended
December 31, 2002
-------------------------- Total
Turbine Turbine
Turbine CIP Restructuring Restructuring
Description Write-Off Accrual Charge
- -------------------------------------------------------------------------------------- ----------- ------------- -------------
Turbine write-offs and contract restructuring charges................................. $ 182,534 $ 24,824 $ 207,358
The following table sets forth in the Company's turbine restructuring
reserves as of December 31, 2003 (in thousands):
As of As of
December 31, Adjustments to December 31,
2002 Payments Accrual(1) 2003
------------ ---------- -------------- ------------
Turbine restructuring accrual............................................ $ 24,824 $ (15,805) $ (473) $ 8,546
- ------------
<FN>
(1) In March 2003, it was determined that the actual invoices for the steam
turbine equipment cancellations were less than the amount which had been
accrued as of December 31, 2002.
</FN>
-134-
The following table sets forth in the Company's restructuring reserves as of
December 31, 2004 (in thousands):
As of As of
December 31, Adjustments to December 31,
2003 Payments Accrual(1) 2004
------------ ---------- -------------- ------------
Turbine restructuring accrual............................................ $ 8,546 $ (4,498) $ -- $ 4,048
In July 2003, the Company completed a restructuring of its existing
agreements with Siemens Westinghouse Power Corporation for 20 gas and 2 steam
turbines. The new agreement provides for later payment dates, which are in line
with the Company's construction program. The table below sets forth future
turbine payments for construction and development projects, as well as for
unassigned turbines. It includes previously delivered turbines, payments and
delivery year for the last turbine to be delivered as well as payment required
for the potential cancellation costs of the remaining 38 gas and steam turbines.
The table does not include payments that would result if the Company were to
release for manufacturing any of these remaining 38 turbines.
Units to be
Year Total Delivered
- ------------------------------------------------------ ---------- -----------
(In thousands)
2005.................................................. $ 27,463 1
2006.................................................. 4,862 --
2007.................................................. 977 --
---------- ----
Total............................................... $ 33,302 1
========== ====
Other Restructuring Charges -- In fiscal years 2002, 2003 and 2004, in
connection with management's plan to reduce costs and improve operating
efficiencies, the Company recorded restructuring charges primarily comprised of
severance and benefits related to the involuntary termination of employees and
charges related to the vacancy of a number of facilities.
The following table sets forth the Company's restructuring reserves
relating to its vacancy of various facilities as of December 31, 2003 (in
thousands):
As of Reclass As of
December 31, from Adjustments December 31,
2002 Additions Long-term Amortization to Accrual 2003
------------ --------- --------- ------------ ----------- ------------
Accrued rent -- Short-term............................. $ 4,009 $ 2,062 $ 825 $ (3,718) $ (166) $ 3,012
Accrued rent -- Long-term.............................. 2,370 8,341 (825) (162) 195 9,919
------- ------- ------ -------- ------ --------
Total accrued rent liability.......................... $ 6,379 $10,403 $ -- $ (3,880) $ 29 $ 12,931
======= ======= ====== ======== ====== ========
The following table sets forth the Company's restructuring reserves
relating to its vacancy of various facilities as of December 31, 2004 (in
thousands):
As of Reclass As of
December 31, from Adjustments December 31,
2003 Additions Long-term Amortization Accretion to Accrual 2004
------------ --------- --------- ------------ --------- ----------- ------------
Accrued rent -- Short-term................. $ 3,012 $ 1,313 $ 2,512 $ (2,585) $ -- $ 12 $ 4,264
Accrued rent -- Long-term.................. 9,919 354 (2,512) -- 1,325 54 9,140
-------- ------- ------- --------- ------- ---- --------
Total accrued rent liability............... $ 12,931 $ 1,667 $ -- $ (2,585) $ 1,325 $ 66 $ 13,404
======== ======= ======= ========= ======= ==== ========
The 2003 charge of $10.4 million was recorded in the "Sales, general and
administrative expense" line item on the Consolidated Statements of Operations
for the year ended December 31, 2003. In 2004 $1.5 million of the vacancy
related charges were recorded in the "Discontinued operations, net" line and
$0.1 million in the "Sales, general and administrative expense" line of the
Consolidated Statement of Operations as of December 31, 2004.
-135-
The following table sets forth the Company's restructuring reserves
relating to its involuntary termination of employees as of December 31, 2003 (in
thousands):
As of As of
December 31, December 31,
2002 Additions Payments Adjustments 2003
------------ --------- -------- ----------- ------------
Severance liability.................................................. $ 1,556 $ 3,914 $(5,191) $ 414 $ 693
The following table sets forth the Company's restructuring reserves
relating to its involuntary termination of employees as of December 31, 2004 (in
thousands):
As of As of
December 31, December 31,
2003 Additions Payments Adjustments 2004
------------ --------- -------- ----------- ------------
Severance liability.................................................. $ 693 $ 6,154 $(5,292) $(1,555) $ --
Severance-related charges of $1.1 million were recorded in the "Plant
operating expense" line with the remaining $2.8 million in the "Selling, general
and administrative expense" line of the Consolidated Statements of Operations
for the year ended December 31, 2003. Severance-related charges of $6.2 million
were recorded in the "Discontinued operations, net" line of the Consolidated
Statement of Operations for the year ended December 31, 2004.
Power Plant Operating Leases -- The Company has entered into long-term
operating leases for power generating facilities, expiring through 2049,
including renewal options. Many of the lease agreements provide for renewal
options at fair value, and some of the agreements contain customary restrictions
on dividends, additional debt and further encumbrances similar to those
typically found in project finance agreements. In accordance with SFAS No. 13
and SFAS No. 98 the Company's operating leases are not reflected on our balance
sheet. Lease payments on the Company's operating leases which contain escalation
clauses or step rent provisions are recognized on a straight-line basis. Certain
capital improvements associated with leased facilities may be deemed to be
leasehold improvements and are amortized over the shorter of the term of the
lease or the economic life of the capital improvement. Future minimum lease
payments under these leases are as follows (in thousands):
Initial
Year 2005 2006 2007 2008 2009 Thereafter Total
------- -------- -------- -------- -------- -------- ---------- ----------
Watsonville.................................... 1995 $ 2,905 $ 2,905 $ 2,905 $ 2,905 $ 4,065 $ -- $ 15,685
Greenleaf...................................... 1998 8,723 8,650 8,650 7,495 8,490 29,643 71,651
Geysers........................................ 1999 55,890 47,991 47,150 42,886 34,566 106,017 334,500
KIAC........................................... 2000 24,077 23,875 23,845 24,473 24,537 240,082 360,889
Rumford/Tiverton............................... 2000 44,942 45,000 45,000 45,000 45,000 563,292 788,234
South Point.................................... 2001 9,620 9,620 9,620 9,620 9,620 307,190 355,290
RockGen........................................ 2001 27,031 26,088 27,478 28,732 29,360 169,252 307,941
-------- -------- -------- -------- -------- ---------- ----------
Total......................................... $173,188 $164,129 $164,648 $161,111 $155,638 $1,415,476 $2,234,190
======== ======== ======== ======== ======== ========== ==========
In 2004, 2003, and 2002, rent expense for power plant operating leases
amounted to $105.9 million, $112.1 million and $111.0 million, respectively.
Calpine guarantees $1.6 billion of the total future minimum lease payments of
its consolidated subsidiaries.
On May 19, 2004, the Company restructured the King City power plant
operating lease. Due to the lease extension and other modifications to the
original lease, the lease classification was reevaluated under SFAS No. 13 and
determined to be a capital lease. See Notes 3 and 13 for more information on the
restructuring.
Production Royalties and Leases -- The Company is committed under numerous
geothermal leases and right-of-way, easement and surface agreements. The
geothermal leases generally provide for royalties based on production revenue
with reductions for property taxes paid. The right-of-way, easement and surface
agreements are based on flat rates or adjusted based on CPI changes and are not
material. Under the terms of most geothermal leases, prior to May 1999, when the
Company consolidated the steam field and power plant operations in Lake and
Sonoma Counties in northern California ("The Geysers"), royalties were based on
-136-
steam and effluent revenue. Following the consolidation of operations, the
royalties began to accrue as a percentage of electrical revenues. Certain
properties also have net profits and overriding royalty interests that are in
addition to the land base lease royalties. Some lease agreements contain clauses
providing for minimum lease payments to lessors if production temporarily ceases
or if production falls below a specified level.
Production royalties for gas-fired and geothermal facilities for the years
ended December 31, 2004, 2003, and 2002, were $28.7 million, $24.9 million and
$17.6 million, respectively.
Office and Equipment Leases -- The Company leases its corporate, regional
and satellite offices as well as some of its office equipment under
noncancellable operating leases expiring through 2014. Future minimum lease
payments under these leases are as follows (in thousands):
2005....................................................... $ 29,244
2006....................................................... 24,415
2007....................................................... 22,299
2008....................................................... 21,291
2009....................................................... 21,127
Thereafter................................................. 58,172
-----------
Total.................................................... $ 176,548
===========
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 2004,
2003, and 2002, rent expense for noncancellable operating leases amounted to
$29.7 million, $21.6 million and $25.8 million, respectively.
Natural Gas Purchases -- The Company enters into gas purchase contracts of
various terms with third parties to supply gas to its gas-fired cogeneration
projects.
Gas Pipeline Transportation in Canada -- To support production and
marketing operations, Calpine, through CES, has firm commitments in the ordinary
course of business for gathering, processing and transmission services that
require the Company to deliver certain minimum quantities of natural gas to
third parties or pay the corresponding tariffs. The agreements expire at various
times through 2017. Estimated payments to be made under these arrangements are
$39.9 million, $33.4 million, $31.8 million, $31.1 million, $27.8 million and
$115.0 million for each of the next five years and thereafter, respectively.
Guarantees -- As part of normal business, Calpine enters into various
agreements providing, or otherwise arranges, financial or performance assurance
to third parties on behalf of its subsidiaries. Such arrangements include
guarantees, standby letters of credit and surety bonds. These arrangements are
entered into primarily to support or enhance the creditworthiness otherwise
attributed to a subsidiary on a stand-alone basis, thereby facilitating the
extension of sufficient credit to accomplish the subsidiaries' intended
commercial purposes.
Calpine routinely issues guarantees to third parties in connection with
contractual arrangements entered into by Calpine's direct and indirect wholly
owned subsidiaries in the ordinary course of such subsidiaries' respective
business, including power and natural gas purchase and sale arrangements and
contracts associated with the development, construction, operation and
maintenance of Calpine's fleet of power generating facilities and natural gas
facilities. Under these guarantees, if the subsidiary in question were to fail
to perform its obligations under the guaranteed contract, giving rise to a
default and/or an amount owing by the subsidiary to the third party under the
contract, Calpine could be called upon to pay such amount to the third party or,
in some instances, to perform the subsidiary's obligations under the contract.
It is Calpine's policy to attempt to negotiate specific limits or caps on
Calpine's overall liability under these types of guarantees; however, in some
instances, Calpine's liability is not limited by way of such a contractual
liability cap.
-137-
At December 31, 2004, guarantees of subsidiary debt, standby letters of
credit and surety bonds to third parties and guarantees of subsidiary operating
lease payments and their respective expiration dates were as follows (in
thousands):
Commitments Expiring 2005 2006 2007 2008 2009 Thereafter Total
- ------------------------------------------------ -------- -------- -------- ---------- -------- ---------- ----------
Guarantee of subsidiary debt....................... $ 18,333 $ 16,284 $ 18,798 $1,930,657 $ 19,848 $1,133,896 $3,137,816
Standby letters of credit(1)(3).................... 589,230 3,641 2,802 400 -- -- 596,073
Surety bonds(2)(3)................................. -- -- -- -- -- 12,531 12,531
Guarantee of subsidiary operating lease
payments(3)...................................... 83,169 81,772 82,487 115,604 113,977 1,163,783 1,640,792
-------- -------- -------- ---------- -------- ---------- ----------
Total............................................. $690,732 $101,697 $104,087 $2,046,661 $133,825 $2,310,210 $5,387,212
======== ======== ======== ========== ======== ========== ==========
- ------------
<FN>
(1) The standby letters of credit disclosed above include those disclosed in
Notes 12, 15 and 16.
(2) The surety bonds do not have expiration or cancellation dates.
(3) These are off balance sheet obligations.
</FN>
The balance of the guarantees of subsidiary debt, standby letters of credit
and surety bonds were as follows (in thousands):
Balance at December 31,
----------------------------
2004 2003
------------ -------------
Guarantee of subsidiary debt...................... $ 3,137,816 $ 4,102,829
Standby letters of credit......................... 596,073 410,803
Surety bonds...................................... 12,531 70,480
------------ -------------
$ 3,746,420 $ 4,584,112
============ =============
The Company has guaranteed the principal payment of $2,139.7 million and
$2,448.6 million, as of December 31, 2004 and 2003, respectively, of Senior
Notes for two wholly owned finance subsidiaries of Calpine, Calpine Canada
Energy Finance ULC and Calpine Canada Energy Finance II ULC. As of December 31,
2004, the Company has guaranteed $275.1 million and $72.4 million, respectively,
of project financing for the Broad River Energy Center and Pasadena Power Plant
and $291.6 million and $71.8 million, respectively, as of December 31, 2003, for
these power plants. In 2004 and 2003 the Company has debenture obligations in
the amount of $517.5 million and $1,153.5 million, respectively, the payment of
which will fund the obligations of the Trusts (see Note 12 for more
information). The Company agreed to indemnify Duke Capital Corporation $101.4
million and $101.7 million as of December 31, 2004 and 2003, respectively, in
the event Duke Capital Corporation is required to make any payments under its
guarantee of the lease of the Hidalgo Energy Center. As of December 31, 2004 and
2003, the Company has also guaranteed $31.7 million and $35.6 million,
respectively, of other miscellaneous debt. All of the guaranteed debt is
recorded on the Company's Consolidated Balance Sheet.
Calpine has guaranteed the payment of a portion of the rents due under the
lease of the Greenleaf generating facilities in California, which lease is
between an owner trustee acting on behalf of Union Bank of California, as
lessor, and a Calpine subsidiary, Calpine Greenleaf, Inc., as lessee. Calpine
does not currently meet the requirements of a financial covenant contained in
the guarantee agreement. The lessor has waived this non-compliance through April
30, 2005, and Calpine is currently in discussions with the lessor concerning the
possibility of modifying the lease and/or Calpine's guarantee thereof so as to
eliminate or modify the covenant in question. In the event the lessor's waiver
were to expire prior to completion of this amendment, the lessor could at that
time elect to accelerate the payment of certain amounts owing under the lease,
totaling approximately $15.9 million. In the event the lessor were to elect to
require Calpine to make this payment, the lessor's remedy under the guarantee
and the lease would be limited to taking steps to collect damages from Calpine;
the lessor would not be entitled to terminate or exercise other remedies under
the Greenleaf lease.
-138-
In connection with several of the Company's subsidiaries' lease financing
transactions (Greenleaf, Pasadena, Broad River, RockGen and South Point) the
insurance policies the Company has in place do not comply in every respect with
the insurance requirements set forth in the financing documents. The Company has
requested from the relevant financing parties, and is expecting to receive,
waivers of this noncompliance. While failure to have the required insurance in
place is listed in the financing documents as an event of default, the financing
parties may not unreasonably withhold their approval of the Company's waiver
request so long as the required insurance coverage is not reasonably available
or commercially feasible and the Company delivers a report from its insurance
consultant to that effect.
The Company has delivered the required insurance consultant reports to the
relevant financing parties and therefore anticipates that the necessary waivers
will be executed shortly.
Calpine routinely arranges for the issuance of letters of credit and
various forms of surety bonds to third parties in support of its subsidiaries'
contractual arrangements of the types described above and may guarantee the
operating performance of some of its partially owned subsidiaries up to the
Company's ownership percentage. The letters of credit outstanding under various
credit facilities support CES risk management, and other operational and
construction activities. Of the total letters of credit outstanding, $2.5
million and $14.5 million were issued to support CES risk management at December
31, 2004 and 2003, respectively. In the event a subsidiary were to fail to
perform its obligations under a contract supported by such a letter of credit or
surety bond, and the issuing bank or surety were to make payment to the third
party, Calpine would be responsible for reimbursing the issuing bank or surety
within an agreed timeframe, typically a period of 1 to 10 days. To the extent
liabilities are incurred as a result of activities covered by letters of credit
or the surety bonds, such liabilities are included in the Consolidated Balance
Sheets.
At December 31, 2004, investee debt was $133.9 million. Based on the
Company's ownership share of each of the investments, the Company's share would
be approximately $46.6 million. However, all such debt is non-recourse to the
Company.
In the course of its business, Calpine and its subsidiaries have entered
into various purchase and sale agreements relating to stock and asset
acquisitions or dispositions. These purchase and sale agreements customarily
provide for indemnification by each of the purchaser and the seller, and/or
their respective parent, to the counter-party for liabilities incurred as a
result of a breach of a representation or warranty by the indemnifying party.
These indemnification obligations generally have a discrete term and are
intended to protect the parties against risks that are difficult to predict or
impossible to quantify at the time of the consummation of a particular
transaction. The Company has no reason to believe that it currently has any
material liability relating to such routine indemnification obligations.
Additionally, Calpine and its subsidiaries from time to time assume other
indemnification obligations in conjunction with transactions other than purchase
or sale transactions. These indemnification obligations generally have a
discrete term and are intended to protect our counterparties against risks that
are difficult to predict or impossible to quantify at the time of the
consummation of a particular transaction, such as the costs associated with
litigation that may result from the transaction. The Company has no reason to
believe that it currently has any material liability relating to such routine
indemnification obligations.
Calpine has in a few limited circumstances directly or indirectly
guaranteed the performance of obligations by unrelated third parties. These
circumstances have arisen in situations in which a third party has contractual
obligations with respect to the construction, operation or maintenance of a
power generating facility or related equipment owned in whole or in part by
Calpine. Generally, the third party's obligations with respect to related
equipment are guaranteed for the direct or indirect benefit of Calpine by the
third party's parent or other party. A financing party or investor in such
facility or equipment may negotiate for Calpine also to guarantee the
performance of such third party's obligations as additional support for the
third party's obligations. For example, in conjunction with the financing of
California peaker program, Calpine guaranteed for the benefit of the lenders
certain warranty obligations of third party suppliers and contractors. Calpine
has entered into few guarantees of unrelated third party's obligations. Calpine
has no reason to believe that it currently has any liability with respect to
these guarantees.
The Company believes that the likelihood that it would be required to
perform or otherwise incur any significant losses associated with any of these
guarantees is remote.
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Litigation
The Company is party to various litigation matters arising out of the
normal course of business, the more significant of which are summarized below.
The ultimate outcome of each of these matters cannot presently be determined,
nor can the liability that could potentially result from a negative outcome be
reasonably estimated presently for every case. The liability the Company may
ultimately incur with respect to any one of these matters in the event of a
negative outcome may be in excess of amounts currently accrued with respect to
such matters and, as a result of these matters, may potentially be material to
the Company's Consolidated Financial Statements.
Securities Class Action Lawsuits. Beginning on March 11, 2002, fifteen
securities class action complaints were filed in the U.S. District Court for the
Northern District of California against Calpine and certain of its employees,
officers, and directors. All of these actions were ultimately assigned to Judge
Saundra Brown Armstrong, and Judge Armstrong ordered the actions consolidated
for all purposes on August 16, 2002, as In re Calpine Corp. Securities
Litigation, Master File No. C 02-1200 SBA. There is currently only one claim
remaining from the consolidated actions: a claim for violation of Section 11 of
the Securities Act of 1933 ("Securities Act"). The Court has dismissed all of
the claims brought under Section 10(b) of the Securities Exchange Act of 1934
with prejudice.
On October 17, 2003, plaintiffs filed their third amended complaint
("TAC"), which alleges violations of Section 11 of the Securities Act by
Calpine, Peter Cartwright, Ann B. Curtis and Charles B. Clark, Jr. The TAC
alleges that the registration statement and prospectuses for Calpine's 2011
Notes contained materially false or misleading statements about the factors that
caused the power shortages in California in 2000-2001 and the resulting increase
in wholesale energy prices. The TAC alleges that the true but undisclosed cause
of the energy crisis is that Calpine and other power producers were engaging in
physical withholding of electricity. In discovery, plaintiff has argued that the
TAC is not based solely on allegedly concealed physical withholding, but instead
is based on alleged undisclosed market manipulation in the form of physical
withholding, economic withholding, and trading strategies. The TAC defines the
potential class to include all purchasers of the Notes pursuant to the
registration statement and prospectuses on or before January 27, 2003. The Court
has not yet certified the class. The class certification hearing will be set for
May 3, 2005.
On April 15, 2004, The Policemen and Firemen Retirement System of the City
of Detroit (the "Detroit Fund") filed a request to be appointed as lead
plaintiff in the case. The Court granted the Detroit Fund's request for
appointment as lead plaintiff on May 7, 2004. The Court also approved the
Detroit Fund's choice of Kohn, Swift & Graf, P.C. (Philadelphia) as lead counsel
for the class.
At the Court's invitation, defendants subsequently moved for summary
judgment on grounds that the Section 11 claim was barred by the statute of
limitations. On November 2, 2004, the Court denied the motion on grounds that
defendants had not established as a matter of law that plaintiff was on notice
of the alleged misstatement prior to January 27, 2002, one year before plaintiff
first alleged that Calpine had misrepresented the causes of the energy crisis.
The Court has set a November 7, 2005 trial date. Fact discovery will close on
July 1, 2005. We consider the lawsuit to be without merit and intend to continue
to defend vigorously against the allegations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. This case is
a Section 11 case brought as a class action on behalf of purchasers in Calpine's
April, 2002 stock offering. This case was filed in San Diego County Superior
Court on March 11, 2003, but defendants won a motion to transfer the case to
Santa Clara County. Defendants in this case are Calpine, Cartwright, Curtis,
John Wilson, Kenneth Derr, George Stathakis, CSFB, Banc of America Securities,
Deutsche Bank Securities, and Goldman, Sachs & Co. Plaintiff is the Hawaii
Structural Ironworkers Pension Trust Fund.
The Hawaii Fund alleges that the prospectus and registration statement for
the April 2002 offering had false or misleading statements regarding: Calpine's
actual financial results for 2000 and 2001; Calpine's projected financial
results for 2002; Cartwright's agreement not to sell or purchase shares within
90 days of the offering; and Calpine's alleged involvement in "wash trades." The
core allegation of the complaint is that a March 2003 restatement (concerning
two sales-leaseback transactions) revealed that Calpine had misrepresented its
financial results in the prospectus/registration statement for the April 2002
offering.
There is no discovery cut off date or trial date in this action. The next
scheduled court hearing will be a case management conference on July 5, 2005, at
which time the court should set a discovery deadline and trial date. We consider
this lawsuit to be without merit and intend to continue to defend vigorously
against the allegations.
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Phelps v. Calpine Corporation, et al. On April 17, 2003, James Phelps filed
a class action complaint in the Northern District of California, alleging claims
under the Employee Retirement Income Security Act ("ERISA"). On May 19, 2003, a
nearly identical class action complaint was filed in the Northern District by
Lenette Poor-Herena. The parties agreed to have both of the ERISA actions
assigned to Judge Armstrong, who oversees the above-described federal securities
class action and the Gordon derivative action (see below). On August 20, 2003,
pursuant to an agreement between the parties, Judge Armstrong ordered that the
two ERISA actions be consolidated under the caption, In re Calpine Corp. ERISA
Litig., Master File No. C 03-1685 SBA (the "ERISA Class Action"). Plaintiff
James Phelps filed a consolidated ERISA complaint on January 20, 2004
("Consolidated Complaint"). Ms. Poor-Herena is not identified as a plaintiff in
the Consolidated Complaint.
The Consolidated Complaint defines the class as all participants in, and
beneficiaries of, the Calpine Corporation Retirement Savings Plan (the "Plan")
for whose accounts investments were made in Calpine stock during the period from
January 5, 2001 to the present. The Consolidated Complaint names as defendants
Calpine, the members of its Board of Directors, the Plan's Advisory Committee
and its members (Kati Miller, Lisa Bodensteiner, Rick Barraza, Tom Glymph,
Patrick Price, Trevor Thor, Bob McCaffrey, and Bryan Bertacchi), signatories of
the Plan's Annual Return/Report of Employee Benefit Plan Forms 5500 for 2001 and
2002 (Pamela J. Norley and Marybeth Kramer-Johnson, respectively), an employee
of a consulting firm hired by the Plan (Scott Farris), and unidentified
fiduciary defendants.
The Consolidated Complaint alleges that defendants breached their fiduciary
duties involving the Plan, in violation of ERISA, by misrepresenting Calpine's
actual financial results and earnings projections, failing to disclose certain
transactions between Calpine and Enron that allegedly inflated Calpine's
revenues, failing to disclose that the shortage of power in California during
2000-2001 was due to withholding of capacity by certain power companies, failing
to investigate whether Calpine common stock was an appropriate investment for
the Plan, and failing to take appropriate actions to prevent losses to the Plan.
In addition, the consolidated ERISA complaint alleges that certain of the
individual defendants suffered from conflicts of interest due to their sales of
Calpine stock during the class period.
Defendants moved to dismiss the consolidated complaint. At a February 11,
2005 hearing, Judge Armstrong granted the motion and dismissed three of the four
claims with prejudice. The fourth claim was dismissed with leave to amend. This
claim was based, in part, on the same statements that are at issue in the
Section 11 bond class action. Plan participants did not receive the prospectus
supplements that are at issue in the Section 11 bond class action, but
plaintiffs' counsel told Judge Armstrong that these statements appeared in
documents that were given to Plan participants. Relying on assurances by
plaintiffs' counsel that misstatements about the California energy crisis
appeared in documents that were given to Plan participants (or that were
incorporated by reference into documents given to participants), the Court
granted leave to re-plead this claim. We expect the second amended consolidated
complaint to be due in the near future. We consider this lawsuit to be without
merit and intend to continue to defend vigorously against the allegations.
Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of Calpine against its directors and one of
its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No.
CV803872) and is pending in state superior court of Santa Clara County,
California. Calpine is a nominal defendant in this lawsuit, which alleges claims
relating to purportedly misleading statements about Calpine and stock sales by
certain of the director defendants and the officer defendant. In December 2002,
the court dismissed the complaint with respect to certain of the director
defendants for lack of personal jurisdiction, though plaintiff may appeal this
ruling. In early February 2003, plaintiff filed an amended complaint, naming a
few additional officer defendants. Calpine and the individual defendants filed
demurrers (motions to dismiss) and a motion to stay the case in March 2003. On
July 1, 2003, the Court granted Calpine's motion to stay this proceeding until
the above-described Section 11 action is resolved, or until further order of the
Court. We consider the lawsuit to be without merit.
Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District of
California on behalf of Calpine against its directors, captioned Gordon v.
Cartwright, et al. similar to Johnson v. Cartwright. Motions have been filed to
dismiss the action against certain of the director defendants on the grounds of
lack of personal jurisdiction, as well as to dismiss the complaint in total on
other grounds. In February 2003, plaintiff agreed to stay these proceedings
until the above-described federal Section 11 action is resolved, and to dismiss
without prejudice certain director defendants. On March 4, 2003, plaintiff filed
papers with the court voluntarily agreeing to dismiss without prejudice his
claims against three of the outside directors. We consider this lawsuit to be
without merit.
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International Paper Company v. Androscoggin Energy LLC. In October 2000,
International Paper Company filed a complaint against Androscoggin Energy LLC
("AELLC") alleging that AELLC breached certain contractual representations and
warranties arising out of an Amended Energy Services Agreement ("ESA") by
failing to disclose facts surrounding the termination, effective May 8, 1998, of
one of AELLC's fixed-cost gas supply agreements. The steam price paid by IP
under the ESA is derived from AELLC's cost of gas under its gas supply
agreements. We had acquired a 32.3% economic interest and a 49.5% voting
interest in AELLC as part of the SkyGen transaction, which closed in October
2000. AELLC filed a counterclaim against International Paper Company that has
been referred to arbitration that AELLC may commence at its discretion upon
further evaluation. On November 7, 2002, the court issued an opinion on the
parties' cross motions for summary judgment finding in AELLC's favor on certain
matters though granting summary judgment to International Paper Company on the
liability aspect of a particular claim against AELLC. The court also denied a
motion submitted by IP for preliminary injunction to permit IP to make payment
of funds into escrow (not directly to AELLC) and require AELLC to post a
significant bond.
In mid-April of 2003, IP unilaterally availed itself to self-help in
withholding amounts in excess of $2 million as a setoff for litigation expenses
and fees incurred to date as well as an estimated portion of a rate fund to
AELLC. AELLC has submitted an amended complaint and request for immediate
injunctive relief against such actions. The court heard the motion on April 24,
2003 and ordered that IP must pay the approximate $1.2 million withheld as
attorneys' fees related to the litigation as any such perceived entitlement was
premature, but declined to order injunctive relief on the incomplete record
concerning the offset of $799,000 as an estimated pass-through of the rate fund.
IP complied with the order on April 29, 2003 and tendered payment to AELLC of
the approximate $1.2 million. On June 26, 2003, the court entered an order
dismissing AELLC's amended counterclaim without prejudice to AELLC re-filing the
claims as breach of contract claims in a separate lawsuit. On December 11, 2003,
the court denied in part IP's summary judgment motion pertaining to damages. In
short, the court: (i) determined that, as a matter of law, IP is entitled to
pursue an action for damages as a result of AELLC's breach, and (ii) ruled that
sufficient questions of fact remain to deny IP summary judgment on the measure
of damages as IP did not sufficiently establish causation resulting from AELLC's
breach of contract (the liability aspect of which IP obtained a summary judgment
in December 2002). On February 2, 2004, the parties filed a Final Pretrial Order
with the court. The case recently proceeded to trial, and on November 3, 2004, a
jury verdict in the amount of $41 million was rendered in favor of IP. AELLC was
held liable on the misrepresentation claim, but not on the breach of contract
claim. The verdict amount was based on calculations proffered by IP's damages
experts. AELLC has made an additional accrual to recognize the jury verdict and
the Company has recognized its 32.3% share.
AELLC filed a post-trial motion challenging both the determination of its
liability and the damages award and, on November 16, 2004, the court entered an
order staying the execution of the judgment. The order staying execution of the
judgment has not expired. If the judgment is not vacated as a result of the
post-trial motions, AELLC intends to appeal the judgment.
Additionally, on November 26, 2004, AELLC filed a voluntary petition for
relief under Chapter 11 of the Bankruptcy Code. As noted above, we had acquired
a 32.3% economic interest and a 49.5% voting interest in AELLC as part of the
SkyGen transaction, which closed in October 2000. AELLC is continuing in
possession of its property and is operating and maintaining its business as a
debtor in possession, pursuant to Section 1107(a) and 1108 of the Bankruptcy
Code. No request has been made for the appointment of a trustee or examiner in
the proceeding, and no official committee of unsecured creditors has yet been
appointed by the Office of the United States Trustee.
Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On
November 5, 2003, Panda Energy International, Inc. and certain related parties,
including PLC II, LLC, (collectively "Panda") filed suit against Calpine and
certain of its affiliates in the United States District Court for the Northern
District of Texas, alleging, among other things, that the Company breached
duties of care and loyalty allegedly owed to Panda by failing to correctly
construct and operate the Oneta Energy Center ("Oneta"), which the Company
acquired from Panda, in accordance with Panda's original plans. Panda alleges
that it is entitled to a portion of the profits from Oneta and that Calpine's
actions have reduced the profits from Oneta thereby undermining Panda's ability
to repay monies owed to Calpine on December 1, 2003, under a promissory note on
which approximately $38.6 million (including interest through December 1, 2003)
is currently outstanding and past due. The note is collateralized by Panda's
carried interest in the income generated from Oneta, which achieved full
commercial operations in June 2003. Calpine filed a counterclaim against Panda
Energy International, Inc. (and PLC II, LLC) based on a guaranty and a motion to
dismiss as to the causes of action alleging federal and state securities laws
violations. The court recently granted Calpine's motion to dismiss, but allowed
Panda an opportunity to re-plead. The Company considers Panda's lawsuit to be
without merit and intends to vigorously defend it. Discovery is currently in
progress. The Company stopped accruing interest income on the promissory note
due December 1, 2003, as of the due date because of Panda's default in repayment
of the note.
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California Business & Professions Code Section 17200 Cases, of which the
lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C.,
et al. This purported class action complaint filed in May 2002 against 20 energy
traders and energy companies, including CES, alleges that defendants exercised
market power and manipulated prices in violation of California Business &
Professions Code Section 17200 et seq., and seeks injunctive relief,
restitution, and attorneys' fees. The Company also has been named in eight other
similar complaints for violations of Section 17200. All eight cases were removed
from the various state courts in which they were originally filed to federal
court for pretrial proceedings with other cases in which the Company is not
named as a defendant. However, at the present time, the Company cannot estimate
the potential loss, if any, that might arise from this matter. The Company
considers the allegations to be without merit, and filed a motion to dismiss on
August 28, 2003. The court granted the motion, and plaintiffs have appealed.
Prior to the motion to dismiss being granted, one of the actions, captioned
Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to state
superior court of Alameda County, California. On January 12, 2004, CES was added
as a defendant in Millar. This action includes similar allegations to the other
Section 17200 cases, but also seeks rescission of the long-term power contracts
with the California Department of Water Resources. Millar was removed to federal
court and transferred to the same judge that is presiding over the other Section
17200 cases described above, where it was to be consolidated. However, that
judge recently remanded the case back to state superior court for handling.
Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy
Services, L.P. before the FERC, filed on December 4, 2001, Nevada Section 206
Complaint. On December 4, 2001, Nevada Power Company ("NPC") and Sierra Pacific
Power Company ("SPPC") filed a complaint with FERC under Section 206 of the
Federal Power Act against a number of parties to their power sales agreements,
including Calpine. NPC and SPPC allege in their complaint, that the prices they
agreed to pay in certain of the power sales agreements, including those signed
with Calpine, were negotiated during a time when the spot power market was
dysfunctional and that they are unjust and unreasonable. The complaint therefore
sought modification of the contract prices. The administrative law judge issued
an Initial Decision on December 19, 2002, that found for Calpine and the other
respondents in the case and denied NPC and SPPC the relief that they were
seeking. In a June 26, 2003 order, FERC affirmed the judge's findings and
dismissed the complaint, and subsequently denied rehearing of that order. The
matter is pending on appeal before the United States Court of Appeals for the
Ninth Circuit. The Company has participated in briefing and arguments before the
Ninth Circuit defending the FERC orders, but the Company is not able to predict
at this time the outcome of the Ninth Circuit appeal.
Transmission Service Agreement with Nevada Power Company. On March 16,
2004, NPC filed a petition for declaratory order at FERC (Docket No.
EL04-90-000) asking that an order be issued requiring Calpine and Reliant Energy
Services, Inc. ("Reliant") to pay for transmission service under their
Transmission Service Agreements ("TSAs") with NPC or, if the TSAs are
terminated, to pay the lesser of the transmission charges or a pro rata share of
the total cost of NPC's Centennial Project (approximately $33 million for
Calpine). The Centennial Project involves construction of various transmission
facilities in two phases; Calpine's Moapa Energy Center ("MEC") was scheduled to
receive service under its TSA from facilities yet to be constructed in the
second phase of the Centennial Project. Calpine filed a protest to the petition
asserting that (a) Calpine would take service under the TSA if NPC proceeds to
execute a purchase power agreement ("PPA") with MEC based on MEC's winning bid
in the Request for Proposals that NPC conducted in 2003; (b) if NPC did not
execute a PPA with MEC, Calpine would terminate the TSA and any payment by
Calpine would be limited to a pro rata allocation of certain costs incurred by
NPC in connection with the second phase of the project (approximately $4.5
million in total to date) among the three customers to be served.
On November 18, 2004, FERC issued a decision in Docket No. EL04-90-000
which found that neither Calpine nor Reliant had the right to unilaterally
terminate their respective TSAs, and that upon commencement of service both
Calpine and Reliant would be obligated to pay either the associated demand
charges for service or their respective share of the capital cost associated
with the transmission upgrades that have been made in order to provide such
service. The November 18, 2004 order, however, did not indicate the amount or
measure of damages that would be owed to NPC in the event that either Calpine or
Reliant breached its respective obligations under the TSAs.
On December 10, 2004, NPC filed a request for rehearing of the November 18,
2004 decision, alleging that FERC had erred in holding that a determination of
damages for breach of either Calpine or Reliant was premature and that both
Calpine and Reliant had breached their respective TSAs. Calpine filed an answer
on January 4, 2005 requesting that FERC deny NPC's request for rehearing. NPC's
request for rehearing remains pending before FERC for further consideration. The
Company cannot predict how FERC will rule on NPC's rehearing request.
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In light of the November 18, 2004 order, on November 22, 2004 Calpine
delivered to NPC a notice (the "November 22, 2004 Letter") that it did not
intend to perform its obligations under the Calpine TSA, that NPC should
exercise its duty to mitigate its damages, if any, and that NPC should not incur
any additional costs or expenses in reliance upon the TSA for Calpine's account.
Calpine introduced the November 22, 2004 Letter into evidence in proceedings
before the Public Utilities Commission of Nevada ("PUCN") regarding NPC's third
amendment to its integrated resource plan ("Resource Plan"). In the Resource
Plan, NPC sought approval to proceed with the construction of the second phase
of the Centennial Project (the transmission project intended to serve the
Calpine and Reliant TSAs) (the "HAM Line"). On December 28, 2004, the PUCN
issued an order granting NPC's request to proceed with the construction of the
HAM Line. On January 11, 2005, Calpine filed a petition for reconsideration of
the December 28, 2004 order. On February 9, 2005, the PUCN issued an order
denying Calpine's petitions For reconsideration. At this time Calpine is unable
to predict the impact of the December 28, 2004 and the February 9, 2005 PUCN
orders, if any on the District Court Complaint (discussed below) or any possible
action by NPC before FERC regarding Calpine's notice that it will not perform
its obligations under the Calpine TSA.
Calpine had previously provided security to NPC for Calpine's share of the
HAM Line costs, in the form of a surety bond issued by Fireman's Fund Insurance
Company ("FFIC"). The bond issued by FFIC, by its terms, expired on May 1, 2004.
On or about April 27, 2004, NPC asserted to FFIC that Calpine had committed a
default under the bond by failing to agree to renew or replace the bond upon its
expiration and made demand on FFIC for the full amount of the surety bond,
$33,333,333. On April 29, 2004, FFIC filed a complaint for declaratory relief in
state superior court of Marin County, California in connection with this demand.
FFIC's complaint sought an order declaring that (a) FFIC has no obligation
to make payment under the bond; and (b) if the court were to determine that FFIC
has an obligation to make payment, then (i) Calpine has an obligation to replace
it with funds equal to the amount of NPC's demand against the bond and (ii)
Calpine is obligated to indemnify and hold FFIC harmless for all loss, costs and
fees incurred as a result of the issuance of the bond. Calpine filed an answer
denying the allegations of the complaint and asserting affirmative defenses,
including that it has fully performed its obligations under the TSA and surety
bond. NPC filed a motion to quash service for lack of personal jurisdiction in
California.
On September 3, 2004, the superior court granted NPC's motion, and NPC was
dismissed from the proceeding. Subsequently, FFIC agreed to dismiss the
complaint as to Calpine. On September 30, 2004 NPC filed a complaint in state
district court of Clark County, Nevada against Calpine, Moapa Energy Center,
LLC, FFIC and unnamed parties alleging, among other things, breach by Calpine of
its obligations under the TSA and breach by FFIC of its obligations under the
surety bond. On November 4, 2004, the case was removed to Federal District
Court. At this time, Calpine is unable to predict the outcome of this
proceeding.
Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002, Calpine Canada Natural Gas Partnership ("Calpine Canada") filed a
complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp.
("Enron Canada") owed it approximately US$1.5 million from the sale of gas in
connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron
Canada has not sought bankruptcy relief and has counterclaimed in the amount of
US$18 million. Discovery is currently in progress, and the Company believes that
Enron Canada's counterclaim is without merit and intends to vigorously defend
against it.
Estate of Jones, et al. v. Calpine Corporation. On June 11, 2003, the
Estate of Darrell Jones and the Estate of Cynthia Jones filed a complaint
against Calpine in the United States District Court for the Western District of
Washington. Calpine purchased Goldendale Energy, Inc., a Washington corporation,
from Darrell Jones of National Energy Systems Company ("NESCO"). The agreement
provided, among other things, that upon "Substantial Completion" of the
Goldendale facility, Calpine would pay Mr. Jones (i) the fixed sum of $6.0
million and (ii) a decreasing sum equal to $18.0 million less $0.2 million per
day for each day that elapsed between July 1, 2002, and the date of Substantial
Completion. Substantial Completion of the Goldendale facility occurred in
September 2004 and the daily reduction in the payment amount reduced the $18.0
million payment to zero. The complaint alleged that by not achieving Substantial
Completion by July 1, 2002, Calpine breached its contract with Mr. Jones,
violated a duty of good faith and fair dealing, and caused an inequitable
forfeiture. On July 28, 2003, Calpine filed a motion to dismiss the complaint
for failure to state a claim upon which relief can be granted. The Court granted
Calpine's motion to dismiss the complaint on March 10, 2004. The Court denied
the plaintiffs' subsequent motions for reconsideration and for leave to amend,
granted in part Calpine's motion for an award of attorneys' fees, and entered
judgment dismissing the action. The plaintiffs appealed the dismissal to the
United States Court of Appeals for the Ninth Circuit, where the matter is
pending. Briefing is complete. Oral argument has not yet been scheduled. Calpine
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believes the facility reached Substantial Completion in the second half of 2004.
Calpine thereafter paid to or for the benefit of the Jones estate the fixed sum
of $6 million, which Calpine agreed it was obligated to pay upon Substantial
Completion whenever achieved.
Calpine Energy Services v. Acadia Power Partners. Calpine, through its
subsidiaries, owns 50% of Acadia Power Partners, LLC ("APP") which company owns
the Acadia Energy Center near Eunice, Louisiana (the "Facility"). A Cleco Corp
subsidiary owns the remaining 50% of APP. CES is the purchaser under two power
purchase agreements with APP, which agreements entitle CES to all of the
Facility's capacity and energy. In August 2003 certain transmission constraints
previously unknown to CES and APP began to severely limit the ability of CES to
obtain all of the energy from the Facility. CES has asserted that it is entitled
to certain relief under the purchase agreements, to which assertions APP
disagrees. Accordingly, the parties are engaging in the initial alternative
dispute resolution steps set forth in the power purchase agreements. It is
possible that the dispute will result in binding arbitration pursuant to the
agreements if a settlement is not reached. In addition, CES and APP are
discussing certain billing calculation disputes which relate to efficiency
matters. The dispute covers the time period from June 2002 (commercial operation
date of the plant) to June 2004. It is expected that the parties will be able to
resolve these disputes, and that APP could be liable to CES for an amount up to
$3.1 million.
Hulsey, et al. v. Calpine Corporation. On September 20, 2004, Virgil D.
Hulsey, Jr. (a current employee) and Ray Wesley (a former employee) filed a
class action wage and hour lawsuit against Calpine Corporation and certain of
its affiliates. The complaint alleges that the purported class members were
entitled to overtime pay and Calpine failed to pay the purported class members
at legally required overtime rates. The matter has been transferred to the Santa
Clara County Superior Court and Calpine filed an answer on January 7, 2005,
denying plaintiffs' claims. the parties have agreed to discuss possible
resolutions alternative to litigation.
Michael Portis v. Calpine Corp. -- Department of Labor Claim. On January
25, 2005, Michael Portis ("Portis"), a former employee of Calpine, brought a
complaint to the United States Department of Labor (the "DOL"), alleging that
his employment with the Company was wrongfully terminated. Portis alleges that
Calpine and its subsidiaries evaded sales and use tax in various states and in
doing so filed false tax reports and that his employment was terminated in
retaliation for having reported these allegations to management. Portis claims
that the Company's alleged actions constitute violations of the employee
protection provisions of the Sarbanes Oxley Act of 2002. The Company considers
Portis' claims to be without merit and intends to vigorously defend against the
allegations.
Auburndale Power Partners and Cutrale. Calpine Corporation owns an interest
in the Auburndale Power Partners cogeneration facility (the "APP facility"),
which provides steam to Cutrale, a juice company. The APP facility currently
operates on a "cycling" basis whereby the plant operates only a portion of the
day. During the hours that the APP facility is not operating, APP does not
provide Cutrale Steam. Cutrale has filed an arbitration claim alleging that they
are entitled to damages due to APP's failure to provide them with steam 24 hours
a day. APP believes that Cutrale's position is not supported by the language of
the contract in place between APP and Cutrale and that it will prevail in
arbitration. Nevertheless, to preserve its positive relationship with Cutrale,
APP will continue to try to resolve the matter through a commercial settlement.
Sargent Electric Company v. Kvaerner-Songer Inc., et al. v. CCFC; McCarls
Inc. v. Kvaerner-Songer Inc., CCFC, et al. On June 18, 2003, Kvaerner-Songer
Inc. ("KSI") filed a third-party complaint against CCFC in the Court of Common
Pleas of Berks County, Pennsylvania, alleging material breach of contract and
seeking unspecified damages in an amount in excess of the jurisdictional amount
of $75,000. KSI, along with Kvaerner-Jaddco and Safeco Insurance Company of
America were defendants in a claim filed by Sargent Electric Company ("Sargent")
in the Court of Common Pleas of Berks County, Pennsylvania on October 11, 2002,
which claim alleged breach of contract stemming from Sargent's work as an
electrical subcontractor for KSI during construction of the Ontelaunee project,
claiming, among other things, change in work scope, delays and increased costs.
KSI's third-party claim against CCFC alleged that CCFC was liable to KSI to the
extent that Sargent was entitled to any recovery from KSI. In separate
submittals to us, as part of our claims evaluation process, KSI informed us that
Sargent had submitted claims in the amount of $5.7 million against KSI and KSI
had submitted claims to us in the amount of $3.5 million. R.L. Bondy Inc. had
submitted claims to KSI in the amount of approximately $1.7 million for
miscellaneous work on the Ontelaunee project. On June 1, 2004, CCFC filed an
answer, new matter and counterclaim specifically denying KSI's allegations and
requesting that the third party complaint be dismissed. In addition, CCFC
submitted that KSI had breached its contract with respect to warranty,
commissioning and acceleration matters and requested restitution in the amount
of $7,744,586.
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On February 3, 2004, McCarls Inc. ("McCarls") filed suit against KSI and
CCFC for unjust enrichment relating to certain piping work. McCarls had also
filed claims for promissory estoppel and unjust enrichment against Calpine
Corporation. These claims totaled approximately $12 million. In addition, in
April 2004, KSI filed a cross claim against Calpine and CCFC alleging breach of
contract. On April 12, 2004, the Court overruled preliminary objections filed by
CCFC and Calpine in opposition to the complaint. Following the Court's ruling,
CCFC and Calpine filed a motion to extend the time to answer the McCarls
complaint. The Court allowed Calpine's motion to extend and on May 24, 2004 and
June 1, 2004, Calpine filed its answer, new matter and counterclaim against
McCarls and KSI respectively. Calpine and CCFC denied the allegations of both
McCarls and KSI, requested that the actions be dismissed and filed a
counterclaim for unjust enrichment, promissory estoppel and misrepresentation.
In addition, Calpine filed a request for indemnification against KSI and
asserted that KSI breached its contract with respect to warranty, commissioning
and acceleration matters and requested restitution in the amount of $7,744,586.
On August 20, 2004, Sargent filed a companion case captioned Sargent
Electric v. CCFC for Judgment of Foreclosure of Mechanic's Lien. The underlying
basis for the complaint stems from the same cause of action set forth above. An
answer was to be filed by October 15, but the case was dismissed with prejudice
on September 22, 2004.
The Sargent/KSI and McCarls cases were settled on December 31, 2004 and
January 28, 2005 respectively. Calpine paid a total sum of $14,250,000 to KSI
(the general contractor) as part of the settlement of both cases and KSI paid a
portion to Sargent (the electrical subcontractor) and to McCarls (the piping
subcontractor). Calpine's settlement payment was for construction costs of the
Ontelaunee project.
In addition, the Company is involved in various other claims and legal
actions arising out of the normal course of its business. The Company does not
expect that the outcome of these proceedings will have a material adverse effect
on its financial position or results of operations.
26. Operating Segments
The Company is first and foremost an electric generating company. In
pursuing this business strategy, it was the Company's objective to produce a
portion of its fuel consumption requirements from its own natural gas reserves
("equity gas"). However, with the commitment to a plan of divestiture in the
three months ended June 30, 2005, and the subsequent July 2005 sale of the
Company's remaining oil and gas assets, the Company now has one reportable
segment, Electric Generation and Marketing. No other components of the business
had reached the quantitative criteria to be considered a reportable segment
under SFAS No. 131. See Note 10 for a discussion of the divestiture of the
Company's oil and gas assets. Consequently, the revenue and expense from the Oil
and Gas Production and Marketing reportable segment has been reclassified to
discontinued operations and the assets have been reclassified into current and
long-term assets held for sale. The remaining gas pipeline and transportation
assets previously included in this reportable segment has been reflected in the
table below within Corporate and Other.
Electric Generation and Marketing includes the development, acquisition,
ownership and operation of power production facilities, including related gas
pipeline assets, hedging, balancing, optimization, and trading activity
transacted on behalf of the Company's power generation facilities. Corporate and
other activities necessary to support the Electric Generation and Marketing
reporting segment consists primarily of financing transactions, activities of
the Company's parts and services businesses, including the Company's specialty
data center engineering business, which was divested in the third quarter of
2003, and general and administrative costs.
The Company evaluates performance based upon several criteria including
profits before tax. The accounting policies of the operating segments are the
same as those described in Note 2. The financial results for the Company's
operating segments have been prepared on a basis consistent with the manner in
which the Company's management internally disaggregates financial information
for the purposes of assisting in making internal operating decisions.
Certain costs related to company-wide functions are allocated to each
segment, such as interest expense and interest income, based on a ratio of
segment assets to total assets. The "Depreciation, depletion, and amortization"
line reported below discloses only such amounts as included in "Total Cost of
Revenue" of the Consolidated Statements of Operations. Due to the integrated
nature of the business segments, estimates and judgments have been made in
allocating certain revenue and expense items, and reclassifications have been
made to prior periods to present the allocation consistently.
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Electric
Generation Corporate
and Marketing and Other Total
------------- ------------- -------------
2004
Revenue from external customers .............................................. $ 8,712,934 $ 67,921 $ 8,780,855
Depreciation, depletion, and amortization included in cost of revenue......... 458,065 5,683 463,748
(Income) loss from unconsolidated investments in power projects
and oil and gas properties ................................................. 14,088 -- 14,088
Equipment cancellation and impairment costs .................................. 42,374 -- 42,374
Interest expense ............................................................. 1,030,669 86,131 1,116,800
Interest (income) ............................................................ (50,547) (4,224) (54,771)
(Income) from repurchase of various issuances of debt ........................ -- (246,949) (246,949)
Other (income) expense, net .................................................. (197,996) 76,700 (121,296)
Income (loss) before provision (benefit) for income taxes .................... (596,490) (93,869) (690,359)
Provision (benefit) for income taxes ......................................... (214,012) (33,678) (247,690)
Total assets ................................................................. 25,117,106 2,098,982 27,216,088
Investments in power projects and oil and gas properties ..................... 373,108 -- 373,108
Property additions ........................................................... 1,463,930 23,760 1,487,690
2003
Revenue from external customers .............................................. $ 8,483,497 $ 40,701 $ 8,524,198
Depreciation, depletion, and amortization included in cost of revenue......... 376,038 24,069 400,107
(Income) loss from unconsolidated investments in power projects
and oil and gas properties ................................................. (75,724) -- (75,724)
Equipment cancellation and impairment cost ................................... 64,384 -- 64,384
Interest expense ............................................................. 629,164 86,960 716,124
Interest (income) ............................................................ (34,442) (4,760) (39,202)
(Income) from repurchase of various issuances of debt ........................ -- (278,612) (278,612)
Other (income) expense, net .................................................. (45,886) (103) (45,989)
Income (loss) before provision (benefit) for income taxes .................... (69,600) 9,112 (60,488)
Provision (benefit) for income taxes ......................................... (39,566) 5,179 (34,387)
Cumulative effect of a change in accounting principle, net of tax ............ 183,270 (2,327) 180,943
Total assets ................................................................. 23,988,375 3,315,557 27,303,932
Investments in power plants and oil and gas properties ....................... 443,192 -- 443,192
Property Additions ........................................................... 1,736,529 15,822 1,752,351
2002
Revenue from external customers .............................................. $ 7,076,357 $ 31,452 $ 7,107,809
Depreciation, depletion, and amortization included in cost of revenue......... 270,158 29,853 300,011
(Income) loss from unconsolidated investments in power projects
and oil and gas properties ................................................. (16,552) -- (16,552)
Equipment cancellation and impairment costs .................................. 404,737 -- 404,737
Interest expense ............................................................. 374,258 43,110 417,368
Interest (income) ............................................................ (37,822) (4,357) (42,179)
(Income) from repurchase of various issuances of debt ........................ -- (118,020) (118,020)
Other (income) expense, net .................................................. (43,174) 7,039 (36,135)
Income (loss) before provision (benefit) for income taxes .................... 98,956 (74,683) 24,273
Provision (benefit) for income taxes ......................................... 89,212 (67,330) 21,882
Geographic Area Information
During the year ended December 31, 2004, the Company owned continuing
interests in 88 operating power plants in the United States, three operating
power plants in Canada and TTS in The Netherlands. Geographic revenue and
property, plant and equipment information is based on physical location of the
assets at the end of each period.
United States Canada Europe Total
------------- ------------- ------------- -------------
In thousands)
2004
Total Revenue ..................................... $ 8,637,263 $ 93,072 $ 50,520 $ 8,780,855
Property, plant and equipment, net ................ 18,424,069 498,136 17,215 18,939,420
2003
Total Revenue ..................................... $ 8,379,420 $ 121,218 $ 23,560 $ 8,524,198
Property, plant and equipment, net ................ 17,129,075 474,280 6,137 17,609,492
2002
Total Revenue ..................................... $ 7,077,810 $ 29,999 $ -- $ 7,107,809
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27. California Power Market
California Refund Proceeding. On August 2, 2000, the California Refund
Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric
Company under Section 206 of the Federal Power Act alleging, among other things,
that the markets operated by the California Independent System Operator
("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. FERC
established a refund effective period of October 2, 2000, to June 19, 2001 (the
"Refund Period"), for sales made into those markets.
On December 12, 2002, an Administrative Law Judge issued a Certification of
Proposed Finding on California Refund Liability ("December 12 Certification")
making an initial determination of refund liability. On March 26, 2003, FERC
issued an order (the "March 26 Order") adopting many of the findings set forth
in the December 12 Certification. In addition, as a result of certain findings
by the FERC staff concerning the unreliability or misreporting of certain
reported indices for gas prices in California during the Refund Period, FERC
ordered that the basis for calculating a party's potential refund liability be
modified by substituting a gas proxy price based upon gas prices in the
producing areas plus the tariff transportation rate for the California gas price
indices previously adopted in the California Refund Proceeding. The Company
believes, based on information that the Company has analyzed to date, that any
refund liability that may be attributable to it could total approximately $9.9
million (plus interest, if applicable), after taking the appropriate set-offs
for outstanding receivables owed by the CalPX and CAISO to Calpine. The Company
believes it has appropriately reserved for the refund liability that by its
current analysis would potentially be owed under the refund calculation
clarification in the March 26 Order. The final determination of the refund
liability and the allocation of payment obligations among the numerous buyers
and sellers in the California markets is subject to further Commission
proceedings. It is possible that there will be further proceedings to require
refunds from certain sellers for periods prior to the originally designated
Refund Period. In addition, the FERC orders concerning the Refund Period, the
method for calculating refund liability and numerous other issues are pending on
appeal before the U.S. Court of Appeals for the Ninth Circuit. At this time, the
Company is unable to predict the timing of the completion of these proceedings
or the final refund liability. Thus, the impact on the Company's business is
uncertain.
On April 26, 2004, Dynegy Inc. entered into a settlement of the California
Refund Proceeding and other proceedings with California governmental entities
and the three California investor-owned utilities. The California governmental
entities include the Attorney General, the CPUC, the CDWR, and the EOB. Also, on
April 27, 2004, The Williams Companies, Inc. ("Williams") entered into a
settlement of the California Refund Proceeding and other proceedings with the
three California investor-owned utilities; previously, Williams had entered into
a settlement of the same matters with the California governmental entities. The
Williams settlement with the California governmental entities was similar to the
settlement that Calpine entered into with the California governmental entities
on April 22, 2002. Calpine's settlement resulted in a FERC order issued on March
26, 2004, which partially dismissed Calpine from the California Refund
Proceeding to the extent that any refunds are owed for power sold by Calpine to
CDWR or any other agency of the State of California. On June 30, 2004, a
settlement conference was convened at the FERC to explore settlements among
additional parties. On December 7, 2004, FERC approved the settlement of the
California Refund Proceeding and other proceedings among Duke Energy Corporation
and its affiliates, the three California investor-owned utilities, and the
California governmental entities.
FERC Investigation into Western Markets. On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western United States. This investigation was initiated as a
result of allegations that Enron and others used their market position to
distort electric and natural gas markets in the West. The scope of the
investigation is to consider whether, as a result of any manipulation in the
short-term markets for electric energy or natural gas or other undue influence
on the wholesale markets by any party since January 1, 2000, the rates of the
long-term contracts subsequently entered into in the West are potentially unjust
and unreasonable. On August 13, 2002, the FERC staff issued the Initial Report
on Company-Specific Separate Proceedings and Generic Reevaluations; Published
Natural Gas Price Data; and Enron Trading Strategies (the "Initial Report"),
summarizing its initial findings in this investigation. There were no findings
or allegations of wrongdoing by Calpine set forth or described in the Initial
Report. On March 26, 2003, the FERC staff issued a final report in this
investigation (the "Final Report"). In the Final Report, the FERC staff
recommended that FERC issue a show cause order to a number of companies,
including Calpine, regarding certain power scheduling practices that may have
been in violation of the CAISO's or CalPX's tariff. The Final Report also
recommended that FERC modify the basis for determining potential liability in
the California Refund Proceeding discussed above. Calpine believes that it did
not violate these tariffs and that, to the extent that such a finding could be
made, any potential liability would not be material.
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Also, on June 25, 2003, FERC issued a number of orders associated with
these investigations, including the issuance of two show cause orders to certain
industry participants. FERC did not subject Calpine to either of the show cause
orders. FERC also issued an order directing the FERC Office of Markets and
Investigations to investigate further whether market participants who bid a
price in excess of $250 per megawatt hour into markets operated by either the
CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may
have violated CAISO and CalPX tariff prohibitions. No individual market
participant was identified. The Company believes that it did not violate the
CAISO and CalPX tariff prohibitions referred to by FERC in this order; however,
the Company is unable to predict at this time the final outcome of this
proceeding or its impact on Calpine.
CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our
Qualifying Facilities ("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 by determining the short run avoided cost ("SRAC") energy price
formula. In mid-2000 our QF facilities elected the option set forth in Section
390 of the California Public Utilities Code, which provided QFs the right to
elect to receive energy payments based on the CalPX market clearing price
instead of the SRAC price administratively determined by the CPUC. Having
elected such option, the Company's QF facilities were paid based upon the CalPX
zonal day-ahead clearing price ("CalPX Price") for various periods commencing in
the summer of 2000 until January 19, 2001, when the CalPX ceased operating a
day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine
whether the CalPX Price was the appropriate price for the energy component upon
which to base payments to QFs which had elected the CalPX-based pricing option.
One CPUC Commissioner at one point issued a proposed decision to the effect that
the CalPX Price was the appropriate energy price to pay QFs who selected the
pricing option then offered by Section 390. No final decision, however, has been
issued to date. Therefore, it is possible that the CPUC could order a payment
adjustment based on a different energy price determination. On January 10, 2001,
PG&E filed an emergency motion (the "Emergency Motion") requesting that the CPUC
issue an order that would retroactively change the energy payments received by
QFs based on CalPX-based pricing for electric energy delivered during the period
commencing during June 2000 and ending on January 18, 2001. On April 29, 2004,
PG&E, the Utility Reform Network, a consumer advocacy group, and the Office of
Ratepayer Advocates, an independent consumer advocacy department of the CPUC
(collectively, the "PG&E Parties"), filed a Motion for Briefing Schedule
Regarding True-Up of Payments to QF Switchers (the "April 2004 Motion"). The
April 2004 Motion requests that the CPUC set a briefing schedule in R.99-11-022
to determine what is the appropriate price that should be paid to the QFs that
had switched to the CalPX Price. The PG&E Parties allege that the appropriate
price should be determined using the methodology that has been developed thus
far in the California Refund Proceeding discussed above. Supplemental pleadings
have been filed on the April 2004 Motion, but neither the CPUC nor the assigned
administrative law judge has issued any rulings with respect to either the April
2004 Motion or the initial Emergency Motion. The Company believes that the CalPX
Price was the appropriate price for energy payments for its QFs during this
period, but there can be no assurance that this will be the outcome of the CPUC
proceedings.
City of Lodi Agreement. On February 9, 2001, the Company entered into an
agreement with the City of Lodi (the Northern California Power Agency acted as
agent on behalf of the City of Lodi) whereby CES would sell 25 MW of ATC fixed
price power plus a 1.7 MW day-ahead call option to the City of Lodi for delivery
from January 1, 2002, through December 31, 2011. In September 2002 the City of
Lodi and Calpine agreed to terminate this agreement resulting in a $41.5 million
gain to the Company. The gain is included in Other income in the accompanying
consolidated financial statements.
Geysers Reliability Must Run Section 206 Proceeding. CAISO, EOB, CPUC,
PG&E, San Diego Gas & Electric Company, and Southern California Edison Company
(collectively referred to as the "Buyers Coalition") filed a complaint on
November 2, 2001 at FERC requesting the commencement of a Federal Power Act
Section 206 proceeding to challenge one component of a number of separate
settlements previously reached on the terms and conditions of "reliability must
run" contracts ("RMR Contracts") with certain generation owners, including
Geysers Power Company, LLC, which settlements were also previously approved by
FERC. RMR Contracts require the owner of the specific generation unit to provide
energy and ancillary services when called upon to do so by the ISO to meet local
transmission reliability needs or to manage transmission constraints. The Buyers
Coalition has asked FERC to find that the availability payments under these RMR
Contracts are not just and reasonable. Geysers Power Company, LLC filed an
answer to the complaint in November 2001. To date, FERC has not established a
Section 206 proceeding. The outcome of this litigation and the impact on the
Company's business cannot be determined at the present time.
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28. Subsequent Events
On January 28, 2005, the Company's indirect subsidiary Metcalf Energy
Center, LLC obtained a $100.0 million, non-recourse credit facility for the
Metcalf Energy Center in San Jose, CA. Loans extended to Metcalf under the
facility will fund the balance of construction activities for the 602-megawatt,
natural gas-fired power plant. The project finance facility will mature in July
2008.
On January 31, 2005, the Company received funding on a $260.0 million
offering of Redeemable Preferred Shares, due on July 30, 2005. The Company
offered the shares in a private placement in the United States under Regulation
D under the Securities Act of 1933 and outside of the United States pursuant to
Regulation S under the Securities Act of 1933. The Redeemable Preferred Shares
priced at U.S. LIBOR plus 850 basis points, were offered at 99% of par. The
proceeds from the offering of the shares were used in accordance with the
provisions of the Company's existing bond indentures.
On March 1, 2005, our indirect subsidiary, Calpine Steamboat Holdings, LLC,
closed on a $503.0 million non-recourse project finance facility that will
provide $466.5 million to complete the construction of the Mankato Energy Center
("Mankato") in Blue Earth County, Minnesota, and the Freeport Energy center in
Freeport, Texas. The remaining $36.5 million of the facility provides a letter
of credit for Mankato that is required to serve as collateral available to
Northern States Power Company if Mankato does not meet its obligations under the
power purchase agreement. The project finance facility will initially be
structured as a construction loan, converting to a term loan upon commercial
operations of the plants, and will mature in December 2011. The facility will
initially be priced at LIBOR plus 1.75%.
On March 31, 2005, Deer Park Energy Center, Limited Partnership ("Deer
Park"), an indirect, wholly owned subsidiary of Calpine, entered into an
agreement to sell power to and buy gas from Merrill Lynch Commodities, Inc.
("MLCI"). The agreement covers 650 MW of Deer Park's capacity and deliveries
under the agreement will begin on April 1, 2005 and continue through December
31, 2010. Under the terms of the agreement, Deer Park will sell power to MLCI at
a discount to prevailing market prices at the time the agreement was executed.
In exchange for the discounted pricing, Deer Park received a cash payment of
approximately $195 million and expects to receive additional cash payments as
additional power transactions are executed with discounts to prevailing market
prices. The agreements are derivatives under SFAS No. 133 and because of their
discounted pricing will result in the recognition of a derivative liability. The
upfront payments received by Deer Park from the transaction will be recorded as
cash flow from financing activity in accordance with guidance contained in SFAS
No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities."
Subsequent to December 31, 2004, the Company repurchased $31.8 million in
principal amount of its outstanding 8 1/2% Senior Notes Due 2011 in exchange for
$23.0 million in cash plus accrued interest. The Company also repurchased $48.7
million in principal amount of its outstanding 8 5/8% Senior Notes Due 2010 in
exchange for $35.0 million in cash plus accrued interest. The Company recorded a
pre-tax gain on these transactions in the amount of $22.5 million before
write-offs of unamortized deferred financing costs and the unamortized premiums
or discounts.
29. Quarterly Consolidated Financial Data (unaudited)
The Company's quarterly operating results have fluctuated in the past and
may continue to do so in the future as a result of a number of factors,
including, but not limited to, the timing and size of acquisitions, the
completion of development projects, the timing and amount of curtailment of
operations under the terms of certain power sales agreements, the degree of risk
management and trading activity, and variations in levels of production.
Furthermore, the majority of the dollar value of capacity payments under certain
of the Company's power sales agreements are received during the months of May
through October.
The Company's common stock has been traded on the New York Stock Exchange
since September 19, 1996. There were 2,366 common stockholders of record at
December 31, 2004. No dividends were paid for the years ended December 31, 2004
and 2003. All share data has been adjusted to reflect the two-for-one stock
split effective June 8, 2000, and the two-for-one stock split effective November
14, 2000. The quarterly financial data below has been adjusted to reflect
discontinued operations related to the Company's commitment to a plan of
divestiture of the Saltend Energy Centre and the Company's remaining oil and gas
assets. See Note 10 for a discussion of these subsequent events.
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Quarter Ended
---------------------------------------------------------------
December 31, September 30, June 30, March 31,
------------ ------------- ------------- -------------
(In thousands, except per share amounts)
2004 Common stock price per share:
High............................................................ $ 4.08 $ 4.46 $ 4.98 $ 6.42
Low............................................................. 2.24 2.87 3.04 4.35
2004
Total revenue..................................................... $ 2,203,159 $ 2,458,340 $ 2,215,403 $ 1,903,953
(Income) from repurchase of various issuances of debt............. (76,401) (167,154) (2,559) (835)
Gross profit (loss)............................................... 69,726 227,913 27,307 45,808
Income (loss) from operations..................................... (47,866) 139,869 (38,223) (15,621)
Income (loss) before discontinued operations...................... (229,796) 11,275 (73,711) (150,436)
Discontinued operations, net of tax............................... (53,900) 129,850 45,014 79,244
Net income (loss)................................................. $ (283,696) $ 141,125 $ (28,698) $ (71,192)
Basic earnings per common share:
Income (loss) before discontinued operations.................... $ (0.52) $ 0.03 $ (0.18) $ (0.36)
Discontinued operations, net of tax............................. (0.12) 0.29 0.11 0.19
Net income (loss)............................................... (0.64) 0.32 (0.07) (0.17)
Diluted earnings per common share:
Income (loss) before discontinued operations and dilutive
effect of certain securities................................... $ (0.52) $ 0.03 $ (0.18) $ (0.36)
Dilutive effect of certain securities........................... 2 -- -- --
Income (loss) before discontinued operations.................... (0.52) 0.03 (0.18) (0.36)
Discontinued operations, net of tax............................. (0.12) 0.29 0.11 0.19
Net income (loss)............................................... (0.64) 0.32 (0.07) (0.17)
2003 Common stock price per share:
High............................................................ $ 5.25 $ 8.03 $ 7.25 $ 4.42
Low............................................................. 3.28 4.76 3.33 2.51
2003
Total revenue..................................................... $ 1,794,043 $ 2,582,221 $ 2,084,165 $ 2,063,769
(Income) from repurchase of various issuances of debt............. (64,611) (207,238) (6,763) --
Gross profit...................................................... 69,887 315,855 136,029 85,591
Income (loss) from operations..................................... (63,892) 266,979 122,755 39,931
Income (loss) before discontinued operations...................... (88,885) 112,051 26,849 (76,115)
Discontinued operations, net of tax............................... 28,093 125,731 (50,215) 23,570
Cumulative effect of a change in accounting principle............. 180,414 -- -- 529
Net income (loss)................................................. $ 119,622 $ 237,782 $ (23,366) $ (52,016)
Basic earnings per common share:
Income (loss) before discontinued operations and cumulative
effect of a change in accounting principle..................... $ (0.22) $ 0.29 $ 0.07 $ (0.20)
Discontinued operations, net of tax............................. 0.07 0.32 (0.13) 0.06
Cumulative effect of a change in accounting principle........... 0.44 -- -- --
Net income (loss)............................................... 0.29 0.61 (0.06) (0.14)
Diluted earnings per common share:
Income (loss) before discontinued operations and dilutive
effect of certain securities................................... $ (0.22) $ 0.29 $ 0.07 $ (0.20)
Dilutive effect of certain securities........................... 0.01 (0.03) -- --
Income (loss) before discontinued operations and cumulative
effect of a change in accounting principle..................... (0.21) 0.26 0.07 (0.20)
Discontinued operations, net of tax............................. 0.07 0.25 (0.13) 0.06
Cumulative effect of a change in accounting principle........... 0.43 -- -- --
Net income (loss)............................................... 0.29 0.51 (0.06) (0.14)
- ------------
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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 hereunto duly authorized.
CALPINE CORPORATION
By: /s/ Charles B. Clark, Jr.
------------------------------------
Charles B. Clark, Jr.
Senior Vice President, Controller
Chief Accounting Officer
Date: October 17, 2005
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