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EX-31.1 - CERTIFICATION OF CEO PURSUANT TO SECTION 302 - CALPINE CORPex31_1.htm
EX-32.1 - CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906 - CALPINE CORPex32_1.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 302 - CALPINE CORPex31_2.htm



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________
 
Form 10-Q

 
(Mark One)
 
 
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2010
 
Or
     
 
[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to
 
Commission File No. 001-12079
_______________
 
Calpine Corporation
 
(A Delaware Corporation)
 
I.R.S. Employer Identification No. 77-0212977

717 Texas Avenue, Suite 1000, Houston, Texas 77002
Telephone: (713) 830-8775

Not Applicable
(Former Address)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [X] Yes[   ] No
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). [   ] Yes[   ] No
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 
Large accelerated filer
[X]
Accelerated filer
[   ]
 
Non-accelerated filer
[   ]    (Do not check if a smaller reporting company)
Smaller reporting company
[   ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
[   ] Yes               [X] No
 
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
[X] Yes               [   ] No
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:  444,234,522 shares of Common Stock, par value $.001 per share, outstanding on May 3, 2010.




 
 
 
 
 
 

CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2010

   
 
Page
Definitions
Forward-Looking Statements
Where You Can Find Other Information
   
PART I — FINANCIAL INFORMATION
 
   
Item 1.  Financial Statements
 
Consolidated Condensed Statements of Operations for the Three Months Ended March 31, 2010 and 2009
Consolidated Condensed Balance Sheets at March 31, 2010, and December 31, 2009
Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009
Notes to Consolidated Condensed Financial Statements
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction and Overview
Results of Operations
Commodity Margin and Adjusted EBITDA
Liquidity and Capital Resources
Risk Management and Commodity Accounting
New Accounting Standards and Disclosure Requirements
Item 3.  Quantitative and Qualitative Disclosures About Market Risk
Item 4.  Controls and Procedures
   
PART II — OTHER INFORMATION
 
   
Item 1.  Legal Proceedings
Item 1A.  Risk Factors
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.  Exhibits
Signatures

 


 
ii
 
 
 
 
DEFINITIONS

As used in this Report, the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.

ABBREVIATION
 
DEFINITION
     
2009 Form 10-K
 
Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 25, 2010
     
Adjusted EBITDA
 
EBITDA as adjusted for the effects of (a) impairment charges, (b) reorganization items, (c) major maintenance expense, (d) operating lease expense, (e) any unrealized gains or losses on commodity derivative mark-to-market activity, (f) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (g) stock-based compensation expense, (h) non-cash gains or losses on sales, dispositions or impairments of assets, (i) non-cash gains and losses from intercompany foreign currency translations, (j) any gains or losses on the repurchase or extinguishment of debt and (k) any other extraordinary, unusual or non-recurring items
     
AOCI
 
Accumulated Other Comprehensive Income
     
Average availability
 
Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period
     
Average capacity factor (excluding peakers)
 
The average capacity factor (excluding peakers) is a measure of total actual generation as a percent of total potential generation. It is calculated by dividing (a) total MWh generated by our power plants (excluding peakers) by (b) the product of multiplying (i) the average total MW in operation during the period by (ii) the total hours in the period
     
BLM
 
Bureau of Land Management of the U.S. Department of the Interior
     
Blue Spruce
 
Blue Spruce Energy Center, LLC, an indirect, wholly owned subsidiary that owns Blue Spruce Energy Center, a 310 MW natural gas-fired peaker power plant located in Aurora, Colorado
     
Btu
 
British thermal unit(s), a measure of heat content
     
CalGen
 
Calpine Generating Company, LLC, an indirect, wholly owned subsidiary
     
CalGen Third Lien Debt
 
Together, the $680,000,000 Third Priority Secured Floating Rate Notes Due 2011, issued by CalGen and CalGen Finance Corp.; and the $150,000,000 11 1/2% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance Corp., in each case repaid on March 29, 2007
     
Calpine Equity Incentive Plans
 
Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors
     
CCFC
 
Calpine Construction Finance Company, L.P., an indirect, wholly owned subsidiary
     
CCFC Notes
 
The $1.0 billion aggregate principal amount of 8.0% Senior Secured Notes due 2016 issued May 19, 2009, by CCFC and CCFC Finance Corp.
     
CCFC Old Notes
 
The $415 million total aggregate principal amount of Second Priority Senior Secured Floating Rate Notes Due 2011 issued by CCFC and CCFC Finance, comprising $365 million aggregate principal amount issued August 14, 2003, and $50 million aggregate principal amount issued September 25, 2003, and redeemed, in each case, on June 18, 2009
     
CCFCP
 
CCFC Preferred Holdings, LLC
     
CCFCP Preferred Shares
 
The $300 million of six-year redeemable preferred shares due 2011 issued by CCFCP and redeemed on or before July 1, 2009
     

 
iii
 
 


 ABBREVIATION   DEFINITION
     
CCFC Term Loans
 
The $385 million First Priority Senior Secured Institutional Term Loans due 2009 borrowed by CCFC under the Credit and Guarantee Agreement, dated as of August 14, 2003, among CCFC, the guarantors party thereto, and Goldman Sachs Credit Partners L.P., as sole lead arranger, sole bookrunner, administrative agent and syndication agent, and repaid on May 19, 2009
     
CEHC
 
Conectiv Energy Holding Company, a wholly owned subsidiary of Conectiv
     
Channel Energy Center
 
Our 593 MW natural gas-fired cogeneration power plant located in Houston, Texas
     
Chapter 11
 
Chapter 11 of the U.S. Bankruptcy Code
     
Cogeneration
 
Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations
     
Commodity Collateral Revolver
 
Commodity Collateral Revolving Credit Agreement, dated as of July 8, 2008, among Calpine Corporation as borrower, Goldman Sachs Credit Partners L.P., as payment agent, sole lead arranger and sole bookrunner, and the lenders from time to time party thereto
     
Commodity expense
 
The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense and cash settlements from our marketing, hedging and optimization activities that are included in our mark-to-market activity in fuel and purchased energy expense, but excludes the unrealized portion of our mark-to-market activity
     
Commodity Margin
 
Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance costs, and cash settlements from our marketing, hedging and optimization activities that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenues
     
Commodity revenue
 
The sum of our revenues from power and steam sales, sales of purchased power and natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue, and cash settlements from our marketing, hedging and optimization activities that are included in our mark-to-market activity in operating revenues, but excludes the unrealized portion of our mark-to-market activity
     
Company
 
Calpine Corporation, a Delaware corporation, and its subsidiaries
     
Conectiv
 
Conectiv Energy, a wholly owned subsidiary of PHI
     
Confirmation Order
 
The order of the U.S. Bankruptcy Court entitled “Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code,” entered December 19, 2007, confirming the Plan of Reorganization pursuant to section 1129 of the U.S. Bankruptcy Code
     
CPUC
 
California Public Utilities Commission
     
Director Plan
 
Calpine Corporation 2008 Director Incentive Plan
     
EBITDA
 
Earnings before interest, taxes, depreciation and amortization
     
Effective Date
 
January 31, 2008, the date on which the conditions precedent enumerated in the Plan of Reorganization were satisfied or waived and the Plan of Reorganization became effective
     
Emergence Date Market Capitalization
 
The weighted average trading price of Calpine Corporation’s common stock over the 30-day period following the date on which it emerged from Chapter 11 bankruptcy protection, as defined in and calculated pursuant to Calpine Corporation’s amended and restated certificate of incorporation and reported in its Current Report on Form 8-K filed with the SEC on March 25, 2008
     
EPA
 
U.S. Environmental Protection Agency
     
Equity Plan
 
Calpine Corporation 2008 Equity Incentive Plan
     
Exchange Act
 
U.S. Securities Exchange Act of 1934, as amended
     

 
iv
 
 


 ABBREVIATION    DEFINTION
     
First Lien Credit Facility
 
Credit Agreement, dated as of January 31, 2008, as amended by the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, as borrower, certain subsidiaries of the Company named therein, as guarantors, the lenders party thereto, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, and the other agents named therein
     
First Lien Notes
 
$1.2 billion aggregate principal amount of 7 1/4% senior secured notes due 2017 issued October 21, 2009, in exchange for a like principal amount of term loans under the First Lien Credit Facility
     
GAAP
 
Generally accepted accounting principles in the U.S.
     
Geysers Assets
 
Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 15 operating power plants and one plant not in operation
     
GHG
 
Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
     
Greenfield LP
 
Greenfield Energy Centre LP, a 50% joint venture interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,005 MW natural gas-fired power plant in Ontario, Canada
     
Heat Rate(s)
 
A measure of the amount of fuel required to produce a unit of power
     
ISO
 
Independent System Operator
     
ISO NE
 
ISO New England
     
kWh
 
Kilowatt-hour(s), a measure of power produced
     
LIBOR
 
London Inter-Bank Offered Rate
     
Lyondell
 
Collectively, Lyondell Chemical Co. and certain of its subsidiaries, which filed for protection under Chapter 11 in the U.S. Bankruptcy Court
     
Market Capitalization
 
As of any date, Calpine Corporation’s then market capitalization calculated using the rolling 30-day weighted average trading price of Calpine Corporation’s common stock, as defined in and calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation
     
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
     
MMBtu
 
Million Btu
     
MW
 
Megawatt(s), a measure of plant capacity
     
MWh
 
Megawatt hour(s), a measure of power produced
     
NOL(s)
 
Net operating loss(es)
     
NYISO
 
New York ISO
     
NYMEX
 
New York Mercantile Exchange
     
OCI
 
Other Comprehensive Income
     
OMEC
 
Otay Mesa Energy Center, LLC, an indirect, wholly owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW power plant located in San Diego county, California
     
OTC
 
Over-the-Counter
     
PCF
 
Power Contract Financing, L.L.C.
     
PCF III
 
Power Contract Financing III, LLC
     
PG&E
 
Pacific Gas & Electric Company
     
PHI
 
Pepco Holdings, Inc.
     
PJM
 
Pennsylvania - New Jersey - Maryland Interconnection
     

 
v
 
 


ABBREVIATION    DEFINITION
     
Plan of Reorganization
 
Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on December 19, 2007, as amended, modified or supplemented through the filing of this Report
     
PPA(s)
 
Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
     
PSCo
 
Public Service Company of Colorado, a wholly owned subsidiary of Xcel Energy Inc.
     
REC
 
Renewable Energy Credit
     
RGGI
 
Regional Greenhouse Gas Initiative
     
Rocky Mountain
 
Rocky Mountain Energy Center, LLC, an indirect, wholly owned subsidiary that owns Rocky Mountain Energy Center, a 621 MW combined-cycle, natural gas-fired power plant located in Keenesburg, Colorado
     
SDG&E
 
San Diego Gas & Electric Company
     
SEC
 
U.S. Securities and Exchange Commission
     
SO2
 
Sulfur dioxide
     
Spark spread(s)
 
The difference between the sales price of power per MWh and the cost of fuel to produce it
     
Steam Adjusted Heat Rate
 
The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the kWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
     
TCEQ
 
Texas Commission on Environmental Quality
     
U.S. Bankruptcy Court
 
U.S. Bankruptcy Court for the Southern District of New York
     
U.S. Debtors
 
Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL)
     
VAR
 
Value-at-risk
     
VIE(s)
 
Variable interest entity(ies)
     
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% equity interest
     
 

 
vi
 
 
 
In addition to historical information, this Quarterly Report on Form 10-Q (this “Report”) contains “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the Exchange Act. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:

 
The uncertain length and severity of the current general financial and economic downturn, the timing and strength of an economic recovery, if any, and their impacts on our business including demand for our power and steam products, the ability of customers, suppliers, service providers and other contractual counterparties to perform under their contracts with us and the cost and availability of capital and credit;
 
Financial results that may be volatile and may not reflect historical trends due to, among other things, fluctuations in prices for commodities such as natural gas and power, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;
 
Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
 
Our ability to manage our significant liquidity needs and to comply with covenants under our First Lien Credit Facility, our First Lien Notes and other existing financing obligations;
 
Competition, including risks associated with marketing and selling power in the evolving energy markets;
 
Regulation in the markets in which we participate and our ability to effectively respond to changes in laws and regulations or the interpretation thereof including changing market rules and evolving federal, state and regional laws and regulations including those related to GHG emissions and derivative transactions;
 
Natural disasters such as hurricanes, earthquakes and floods, or acts of terrorism that may impact our power plants or the markets our power plants serve;
 
Seasonal fluctuations of our results and exposure to variations in weather patterns;
 
Disruptions in or limitations on the transportation of natural gas and transmission of power;
 
Our ability to attract, retain and motivate key employees;
 
Our ability to implement our business plan and strategy;
 
Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of wastewater to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
 
Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;
 
Present and possible future claims, litigation and enforcement actions;
 
The expiration or termination of our PPAs and the related results on revenues;
 
Our planned asset divestiture and/or acquisition may not close as planned;
 
Future PJM capacity revenues expected from the planned acquisition of the power generation assets from Conectiv may not occur at expected levels; and
 
Other risks identified in this Report and our 2009 Form 10-K.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this Report. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.


Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to or exhibits included in these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available at the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004.
 

 
 
vii
 


PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

(Unaudited)
 
 
   
Three Months Ended March 31,
 
   
2010
   
2009
 
   
(in millions, except share and
per share amounts)
 
Operating revenues
  $ 1,539     $ 1,677  
                 
Cost of revenue:
               
Fuel and purchased energy expense
    969       1,015  
Plant operating expense
    225       248  
Depreciation and amortization expense
    140       109  
Other cost of revenue
    20       23  
Total cost of revenue
    1,354       1,395  
Gross profit
    185       282  
Sales, general and other administrative expense
    25       45  
Income from unconsolidated investments in power plants
    (7 )     (17 )
Other operating expense
    5       3  
Income from operations
    162       251  
Interest expense
    195       210  
Interest (income)
    (2 )     (6 )
Other (income) expense, net
    6       4  
Income (loss) before reorganization items and income taxes
    (37 )     43  
Reorganization items
          3  
Income (loss) before income taxes
    (37 )     40  
Income tax expense
    11       9  
Net income (loss)
    (48 )     31  
Net loss attributable to the noncontrolling interest
    1       1  
Net income (loss) attributable to Calpine
  $ (47 )   $ 32  
                 
Basic earnings (loss) per common share:
               
Weighted average shares of common stock outstanding (in thousands)
    485,921       485,362  
Net income (loss) per common share attributable to Calpine – basic
  $ (0.10 )   $ 0.07  
                 
Diluted earnings (loss) per common share:
               
Weighted average shares of common stock outstanding (in thousands)
    485,921       485,595  
Net income (loss) per common share attributable to Calpine – diluted
  $ (0.10 )   $ 0.07  



The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
 
 
1
 

CALPINE CORPORATION AND SUBSIDIARIES

(Unaudited)
 
 
   
March 31,
   
December 31,
 
   
2010
   
2009
 
   
(in millions, except
share and per share amounts)
 
ASSETS
           
Current assets:
           
Cash and cash equivalents ($289 and $242 attributable to VIEs. See Note 1)
  $ 1,117     $ 989  
Accounts receivable, net of allowance of $2 and $14
    594       750  
Margin deposits and other prepaid expense
    285       490  
Restricted cash, current ($278 and $322 attributable to VIEs. See Note 1)
    309       508  
Derivative assets, current
    1,943       1,119  
Inventory and other current assets
    210       243  
Total current assets
    4,458       4,099  
                 
Property, plant and equipment, net ($5,777 and $5,319 attributable to VIEs. See Note 1)
    12,034       11,583  
Restricted cash, net of current portion ($41 and $45 attributable to VIEs. See Note 1)
    48       54  
Investments
    84       214  
Long-term derivative assets
    292       127  
Other assets
    563       573  
Total assets
  $ 17,479     $ 16,650  
LIABILITIES & STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 462     $ 578  
Accrued interest payable
    99       54  
Debt, current portion ($121 and $106 attributable to VIEs. See Note 1)
    305       463  
Derivative liabilities, current
    1,971       1,360  
Other current liabilities
    237       294  
Total current liabilities
    3,074       2,749  
                 
Debt, net of current portion ($3,288 and $3,042 attributable to VIEs. See Note 1)
    9,239       8,996  
Deferred income taxes, net of current portion
    58       54  
Long-term derivative liabilities
    362       197  
Other long-term liabilities
    213       208  
Total liabilities
    12,946       12,204  
                 
Commitments and contingencies (see Note 14)
               
Stockholders’ equity:
               
Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding at March 31, 2010 and December 31, 2009
           
Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 444,673,028 shares issued and 444,225,165 shares outstanding at March 31, 2010 and 443,325,827 shares issued and 442,998,255 shares outstanding at December 31, 2009
      1         1  
Treasury stock, at cost, 447,863 shares at March 31, 2010 and 327,572 shares at December 31, 2009
    (5 )     (3 )
Additional paid-in capital
    12,262       12,256  
Accumulated deficit
    (7,587 )     (7,540 )
Accumulated other comprehensive loss
    (135 )     (266 )
Total Calpine stockholders’ equity
    4,536       4,448  
Noncontrolling interest
    (3 )     (2 )
Total stockholders’ equity
    4,533       4,446  
Total liabilities and stockholders’ equity
  $ 17,479     $ 16,650  
 
 
 
The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.

 
2
 
 
 
CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
 
 
   
Three Months Ended March 31,
 
   
2010
   
2009
 
   
(in millions)
 
Cash flows from operating activities:
           
Net income (loss)
  $ (48 )   $ 31  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation and amortization expense (1)
    158       132  
Income from unconsolidated investments in power plants
    (7 )     (17 )
Deferred income taxes
    14       10  
Loss on disposal of assets
    9       10  
Unrealized mark-to-market activity, net
    (109 )     (126 )
Stock-based compensation expense
    6       13  
Other
    3       5  
Change in operating assets and liabilities:
               
Accounts receivable
    161       194  
Derivative instruments
    (37 )     (114 )
Other assets
    228       300  
Accounts payable and accrued expenses
    (103 )     (200 )
Other liabilities
    (5 )     (158 )
Net cash provided by operating activities
    270       80  
Cash flows from investing activities:
               
Purchases of property, plant and equipment
    (66 )     (51 )
Cash acquired due to consolidation of OMEC
    8        
Contributions to unconsolidated investments
          (4 )
Decrease in restricted cash
    212       27  
Other
          1  
Net cash provided by (used in) investing activities
    154       (27 )
Cash flows from financing activities:
               
Repayments of project financing, notes payable and other
    (259 )     (130 )
Borrowings from project financing, notes payable and other
    1       71  
Repayments of First Lien Credit Facility
    (36 )     (15 )
Financing costs
          (7 )
Other
    (2 )     (3 )
Net cash used in financing activities
    (296 )     (84 )
Net increase (decrease) in cash and cash equivalents
    128       (31 )
Cash and cash equivalents, beginning of period
    989       1,657  
Cash and cash equivalents, end of period
  $ 1,117     $ 1,626  
Cash paid during the period for:
               
Interest, net of amounts capitalized
  $ 144     $ 226  
Income taxes
  $ 3     $  
Reorganization items included in operating activities, net
  $     $ 3  
                 
Supplemental disclosure of non-cash investing and financing activities:
               
                 
Settlement of commodity contract with project financing
  $     $ 79  
Change in capital expenditures included in accounts payable
  $ (1 )   $ 10  
__________
(1)
Includes depreciation and amortization that is recorded in sales, general and other administrative expense and interest expense on our Consolidated Condensed Statements of Operations.
 
 
 
 
 

The accompanying notes are an integral part of these
Consolidated Condensed Financial Statements.
 
 
 
3
 

CALPINE CORPORATION AND SUBSIDIARIES

March 31, 2010
(Unaudited)


1.  Basis of Presentation and Summary of Significant Accounting Policies

We are an independent wholesale power generation company engaged in the ownership and operation of natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive power markets in the U.S., including California and Texas. We sell wholesale power, steam, regulatory capacity, renewable energy credits and ancillary services to our customers, including industrial companies, retail power providers, utilities, municipalities, independent electric system operators, marketers and others. We engage in the purchase of natural gas as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric transmission rights to deliver power to our customers. We also enter into natural gas and power, commodity and financial derivative transactions to economically hedge our business risks and optimize our portfolio of power plants.

Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2009, included in our 2009 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to seasonal fluctuations in our revenues, major maintenance expense and volatility of commodity prices.

Consolidation of OMEC — We were required by GAAP to adopt a new accounting standard for VIEs which became effective January 1, 2010 and required us to perform an analysis to determine whether we should consolidate any of our previously unconsolidated VIEs or deconsolidate any of our previously consolidated VIEs. We completed our required analysis and determined that we are the primary beneficiary of OMEC. Accordingly, as required by GAAP, we consolidated OMEC effective January 1, 2010. The consolidation of OMEC on January 1, 2010 was accounted for using historical cost and resulted in the addition to our Consolidated Condensed Balance Sheet of approximately $8 million in cash and cash equivalents, $535 million in net property, plant and equipment, $26 million in other current and non-current assets, $375 million in project debt and $50 million in other current and non-current liabilities and the removal of $144 million representing our investment balance in OMEC. Our Consolidated Condensed Financial Statements as of and for the three months ended March 31, 2010 include the consolidated balances of OMEC. We presented our investment in OMEC’s net assets, revenues and expenses under the equity method of accounting as of December 31, 2009 and for the three months ended March 31, 2009. We made no other changes to our group of subsidiaries that we consolidate as a result of the adoption of this new standard. See Note 4 for further discussion of accounting for our VIEs.

Planned Acquisition and Divestiture/Subsequent Events — On April 20, 2010, we entered into a purchase agreement to acquire all of the power generation assets of Conectiv for $1.65 billion, subject to certain adjustments. The acquisition, once closed, will significantly increase our presence in our North segment. Additionally, we entered into a sales agreement on April 2, 2010 to sell Blue Spruce and Rocky Mountain for $739 million, subject to certain working capital adjustments at closing. See Note 2 for further discussion of our planned acquisition and divestiture.

Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.

Fair Value of Financial Instruments and Derivatives — The carrying values of cash equivalents (including amounts in restricted cash), accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments and Notes 7 and 8 for disclosures regarding the fair values of our derivative instruments.

Concentrations of Credit Risk — Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative assets. Certain of our cash and cash equivalents, as well as our restricted cash balances, exceed FDIC insured limits or are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe are credit-worthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our receivable and derivative counterparties. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity counterparties, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.
 
 
 
4
 

Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At March 31, 2010, and December 31, 2009, we had cash and cash equivalents of $295 million and $264 million, respectively, that were subject to such project finance facilities and lease agreements. Cash and cash equivalent balances that can only be used to settle the obligations of our consolidated VIEs have been disclosed on the face of our Consolidated Condensed Balance Sheets as required under a new accounting standard. See Note 4 for a further discussion of accounting for our VIEs.

Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which are restricted. 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, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 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 on our Consolidated Condensed Balance Sheets and Statements of Cash Flows. The table below represents the components of our restricted cash as of March 31, 2010, and December 31, 2009 (in millions):
 
   
March 31, 2010
 
December 31, 2009
 
   
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
 
Debt service
 
$
41
 
$
24
 
$
65
 
$
193
 
$
25
 
$
218
 
Rent reserve
   
16
   
   
16
   
34
   
   
34
 
Construction/major maintenance
   
105
   
17
   
122
   
87
   
22
   
109
 
Security/project/insurance
   
113
   
   
113
   
146
   
   
146
 
Other
   
34
   
7
   
41
   
48
   
7
   
55
 
Total
 
$
309
 
$
48
 
$
357
 
$
508
 
$
54
 
$
562
 
 
Inventory — At March 31, 2010, and December 31, 2009, we had inventory of $174 million and $209 million, respectively. Inventory primarily consists of spare parts, stored natural gas, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Investments — We use the equity method of accounting to record our net interest in Greenfield LP, a 50% joint venture interest and Whitby, a 50% equity interest where we exercise significant influence over operating and financial policies. As discussed above, we presented our investment in OMEC’s net assets, revenues and expenses under the equity method of accounting as of December 31, 2009 and for the three months ended March 31, 2009. Our share of net income (loss) is calculated according to our equity ownership or according to the terms of the applicable partnership agreement. See Note 4 for further discussion of our VIEs and unconsolidated investments.
 
New Accounting Standards and Disclosure Requirements

Consolidation of VIEs and Additional VIE Disclosures — Effective for interim and annual periods beginning after November 15, 2009, GAAP amended the accounting standard for determining which enterprise is the primary beneficiary of a VIE, added additional VIE disclosure requirements and amended guidance for determining whether an entity is a VIE. The new standard generally replaces the quantitative-based risks and rewards calculation for determining which enterprise, if any, is the primary beneficiary of a VIE to a more qualitative assessment with an approach focused on identifying which enterprise has the power to direct the activities of a VIE that most significantly impacts the VIE’s economic performance and also has the obligation to absorb losses or receive benefits from the VIE. We completed our analysis for the three months ended March 31, 2010, and determined that the consolidation of OMEC was required. See Note 4 for further discussion of implementation of this new accounting standard.

The new standard and disclosure requirements also add:

 
A requirement to perform ongoing reassessments each reporting period of whether we are the primary beneficiary of our VIEs, which could require us to consolidate our VIEs that are currently not consolidated or deconsolidate our VIEs that are currently consolidated based upon our reassessments in future periods.

 
Disclosure provisions to present separately on the face of the statement of financial position the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. Our Consolidated Condensed Balance Sheets include these required disclosures. The new standard also reduces required disclosures for consolidated VIEs without such restrictions if we are the equity holder and primary beneficiary.

 
An additional reconsideration event for determining whether an entity is a VIE if any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE’s economic performance.

Fair Value Measurements and Disclosures — In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures” to enhance disclosure requirements relating to different levels of assets and liabilities measured at fair value and to clarify certain existing disclosures. The update requires disclosure of significant transfers in and out of levels 1 and 2 and gross presentation of purchases, sales, issuances and settlements in the level 3 reconciliation of beginning and ending balances. The new disclosure requirements relating to level 3 activity are effective for interim and annual periods beginning after December 15, 2010, and all the other requirements are effective for interim and annual periods beginning after December 15, 2009. We adopted all of the disclosure requirements related to this update for the three months ended March 31, 2010 and 2009. Since this update only requires additional disclosures, this standard did not have a material impact on our results of operations, cash flows or financial condition. See Note 7 for disclosure of our fair value measurements in accordance with these disclosure requirements.

2.  Planned Acquisition and Divestiture

We have entered into certain agreements relating to a planned acquisition and divestiture as described below:
 
Acquisition of Conectiv

Through our wholly owned, indirect subsidiary, New Development Holdings, LLC, we entered into a purchase agreement on April 20, 2010 with PHI, Conectiv and CEHC.

Pursuant to the purchase agreement, we have agreed to purchase from Conectiv, all of the membership interests in CEHC, and thereby acquire all of their power generation assets, which include 18 operating power plants and one plant under construction, with approximately 4,490 MW of capacity (including completion of the power plant under construction and scheduled upgrades) for a purchase price of $1.65 billion in cash, plus the market value of the fuel oil inventory at closing, and subject to other adjustments including the level of working capital and non-fuel oil inventory at closing and actual capital expenditures relative to budgeted capital expenditures through the closing date. We will not acquire CEHC’s trading book, collateral requirements or load-serving auction obligations. In addition, we will not assume any of CEHC’s off-site environmental liabilities or pre-close pension and retirement welfare liabilities. The transaction is targeted to close by June 30, 2010. Effective July 1, 2010, the purchase price will be subject to a per diem reduction for each day closing does not occur of $360,000 in July, $363,500 in August, $237,500 in September, $195,000 in October, $189,500 in November, and $219,500 in December.

The obligations of the parties under the purchase agreement are subject to customary closing conditions, including, among others, obtaining required regulatory, governmental and other third party consents and approvals and the absence of any legal restraint that would make the transaction illegal or otherwise prevent the transaction from closing. The parties have agreed to customary indemnifications for breaches of representations, warranties or covenants made by the parties under the purchase agreement, subject to agreed limitations. The indemnifications for breaches of representations and warranties are capped at $320 million (except with respect to specific representations and in the case of fraud, bad faith or willful misconduct) and subject to a $10 million deductible. In addition, PHI and Conectiv have agreed to indemnify us for specific matters identified in the purchase agreement.
 
 
 
5
 

 
The purchase agreement contains customary termination rights for the parties and may be terminated at any time by us or PHI if the closing fails to occur before December 31, 2010. We have early termination rights if specified events occur or do not occur, or if specified documents are not delivered by certain dates, including audited financial statements of CEHC and its consolidated subsidiaries, PHI lender consents and certain other transaction documents. Termination under certain circumstances, requires liquidated damages to be paid, the amount of which depends on the reason for termination. The liquidated damages that would be payable by PHI range from $20 million to $175 million and the liquidated damages that would be payable by us range from $40 million to $175 million. The parties are not entitled to specific performance under the purchase agreement, other than with respect to certain specified covenants.
 
Sale of Blue Spruce and Rocky Mountain

On April 2, 2010, we, through our wholly owned subsidiaries Riverside Energy Center, LLC and Calpine Development Holdings, Inc., entered into an agreement with PSCo to sell 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, subject to certain working capital adjustments at closing.

Both power plants currently provide power and capacity to PSCo under PPAs, which materially expire in 2013 and 2014, and we will continue to operate Blue Spruce and Rocky Mountain through closing of the transaction which is expected to occur in December 2010. The sales are subject to certain state and federal regulatory approvals. The transaction is expected to free up restricted cash of approximately $90 million at closing. We expect to use the sales proceeds received and freed up restricted cash to repay project debt (with an expected balance of approximately $412 million, after expected repayments prior to closing), for general corporate purposes and focus more resources on our core markets.

As of March 31, 2010, the Blue Spruce and Rocky Mountain assets to be sold primarily consist of property, plant and equipment of approximately $625 million net of accumulated depreciation and amortization of approximately $108 million.

While the agreement to sell Blue Spruce and Rocky Mountain was signed on April 2, 2010, there was considerable uncertainty related to the sales of these assets as of March 31, 2010 during continuing negotiations of acceptable terms and conditions with the buyer. Therefore, we did not classify our Blue Spruce and Rocky Mountain assets as assets held for sale on our Consolidated Condensed Balance Sheet as of March 31, 2010. However, these assets may meet this criteria and be reported as assets held for sale and discontinued operations, as required by GAAP, in future periods.

3.  Property, Plant and Equipment, Net

As of March 31, 2010, and December 31, 2009, the components of property, plant and equipment were stated at cost less accumulated depreciation as follows (in millions):
 
   
March 31, 2010
   
December 31, 2009
 
Buildings, machinery and equipment
  $ 13,907     $ 13,373  
Geothermal properties
    1,092       1,050  
Other
    223       232  
      15,222       14,655  
Less: Accumulated depreciation
    3,436       3,322  
      11,786       11,333  
Land
    73       74  
Construction in progress
    175       176  
Property, plant and equipment, net
  $ 12,034     $ 11,583  
 
 Change in Depreciation Methods, Useful Lives and Salvage Values
 
As further discussed in our 2009 Form 10-K and as described below, effective October 1, 2009, we made two changes to our methods of depreciation including (i) changing from composite depreciation to component depreciation for our rotable parts utilized in our natural gas-fired power plants and (ii) changing from the units of production method to the straight line method for our Geysers Assets. In addition, we completed a life study for each of our natural gas-fired power plants and our Geysers Assets, and changed our estimate of their remaining useful lives of our power plants and the useful lives and salvage values of our rotable parts utilized in our natural gas-fired power plants.
 
 
 
 
6
 
 
 
 
Component Depreciation for Rotable Parts at our Natural Gas-Fired Power Plants — During the three months ended March 31, 2009, we used the composite depreciation method for all of our natural gas-fired power plant assets. Under this method, all assets comprising each power plant were combined into one group and depreciated under a composite depreciation rate. Effective October 1, 2009, we componentized our rotable parts for our natural gas-fired power plant assets for purposes of calculating depreciation. This change in the method of depreciation for rotable parts was considered a change in accounting estimate inseparable from a change in accounting principle, and resulted in changes to our depreciation expense prospectively. This change to component depreciation for our rotable parts utilized in our natural gas-fired power plants also resulted in changes to the useful lives of our rotable parts which are now generally estimated to range from 3 to 18 years. Furthermore, we reduced our estimate of salvage value for our rotable parts to 0.15% of original cost to reflect our expectation with these separable parts. Prior to this change, our composite useful lives for our natural gas-fired power plant assets, including our rotable parts, were 35 years and 40 years for our combined-cycle and our simple-cycle power plant assets, respectively. We also revised the estimated useful lives of our remaining composite pools to 37 years and 47 years for our combined-cycle and simple-cycle power plant assets, respectively based in part on the results of our separate useful life study. Our change in useful lives is considered a change in accounting estimate and resulted in changes to our depreciation expense prospectively.
 
Straight Line Method for our Geysers Assets — During the three months ended March 31, 2009, our Geysers Assets used the units of production method for depreciation. Our units of production depreciation rate was calculated using a depreciable base of the net book value of the Geysers Assets plus the expected future capital expenditures over the economic life of the geothermal reserves. The rate of depreciation per MWh was determined by dividing the depreciable base by total expected future generation. As a result of our change from the units of production method to the straight line method for our Geysers Assets, and based in part on the results of our separate useful life study, we are now using estimates of the remaining composite useful lives of our Geysers Assets which are 59 years and 13 years for our Geysers steam extraction and gathering assets and our Geysers power plant assets, respectively. Our change in the method of depreciation for our Geysers Assets is considered a change in accounting estimate inseparable from a change in accounting principle, and resulted in changes to depreciation expense prospectively.

4.  Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary.

New Accounting Standards for Consolidation of VIEs

Implementation — As further discussed in Note 1, a new accounting standard became effective January 1, 2010 related to accounting for and consolidation of VIEs, which required us to perform an analysis of whether we are the primary beneficiary of our VIEs. The new standard generally replaces the quantitative-based risks and rewards calculation for determining which enterprise, if any, is the primary beneficiary of a VIE to a more qualitative assessment with an approach focused on identifying which enterprise has both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE.
 
Implementation of this new accounting standard also required disclosure of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary separately on the face of our Consolidated Condensed Balance Sheet. In determining which assets met the separate disclosure criteria, we reviewed all of our VIEs and determined this separate disclosure requirement was met where Calpine Corporation was substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment) where the VIE was not a guarantor or grantor under our primary debt facility (the First Lien Credit Facility) and where there were prohibitions of the VIE under agreements that prohibited guaranteeing the debt of Calpine Corporation or its other subsidiaries and where the amounts were material to our financial statements.

In determining which liabilities of our VIEs met the separate disclosure criteria, we reviewed all of our VIEs and determined this separate disclosure requirement was met where our VIEs had project financing that prohibits providing guarantees on the debt of others and where Calpine Corporation has not provided a corporate guarantee and where the amounts were material to our financial statements.


 
7
 

The VIEs meeting the above disclosure criteria are wholly owned subsidiaries of Calpine Corporation which were financed through a combination of project debt and equity provided by Calpine and include natural gas-fired power plants with an aggregate capacity of approximately 7,807 MW. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements between the VIEs, Calpine Corporation and its other wholly owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Calpine Corporation and its other wholly owned subsidiaries have provided financial support in the form of cash contributions in addition to amounts contractually required of approximately $38 million and nil for the three months ended March 31, 2010 and 2009, respectively.
 
As required, we performed an analysis of all of our VIEs effective January 1, 2010 and, with the exception of OMEC, our determination of the primary beneficiary did not change. We concluded that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our analysis to determine the primary beneficiary focused on determining which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis included consideration of the following primary activities which we believe to have a significant impact on a power plant’s financial performance: operations and maintenance, plant dispatch, fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights was based on powers held as of the balance sheet date. Contractual terms that will apply in future periods (such as a purchase or sale option) were not considered in our analysis. Based on our analysis, we determined that we hold the power and rights to direct the most significant activities of all our wholly owned VIEs.

OMEC — During the second quarter of 2007, we determined that SDG&E had a greater variability of risk compared to us based upon the prior consolidation accounting standard, which focused on which party held the greater variability in the obligation to absorb the losses or the right to receive benefits from the VIE or both. We determined that SDG&E held the greater variability as a result of a put option held by OMEC to sell the Otay Mesa Energy Center for $280 million to SDG&E, and a call option held by SDG&E to purchase the Otay Mesa Energy Center for $377 million in 2019. Accordingly, we were not the primary beneficiary, consolidation was not appropriate and we accounted for our investment in OMEC under the equity method of accounting through December 31, 2009.

The transfer of ownership in conjunction with the exercise of the put/call option, which was the driving factor in the quantitative determination of the primary beneficiary under the previous accounting standard, would not occur until 2019. Neither we, nor SDG&E, hold any powers under the combination put/call option as of January 1, 2010. Accordingly, we did not include the benefits and obligations of the put/call option in the new determination of the primary beneficiary under the current accounting standard. Based upon our analysis, we believe the significant activity that has the most impact on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we changed our determination of primary beneficiary from SDG&E to us effective January 1, 2010.

Classifications of VIEs under the Prior Accounting Standard

Our consolidated VIEs as of December 31, 2009, were aggregated into the following classifications in order of priority:

Consolidated VIEs with a Purchase Option — We have five power plants with PPAs or other agreements that provide third parties the option to purchase power plant assets, an equity interest, or a portion of the future cash flows generated from an asset. The purchase options are exercisable only within a specified period of time upon expiration of the PPA or other agreements which expire at various dates occurring 2011 – 2032.

Consolidated Subsidiaries with Project Debt — Certain of our subsidiaries have project debt that contains provisions which we have determined create variability. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default, which we have determined to be unlikely. Accordingly, we are the primary beneficiary of these VIEs. See Note 6 for further information regarding our project debt and Note 1 for information regarding our restricted cash balances.

Consolidated Subsidiaries with PPAs — Certain of our wholly owned subsidiaries have PPAs that are deemed to be a form of subordinated financial support and thus constitute a VIE. For all such VIEs, we have determined that we are the primary beneficiary as we retain the primary risk of loss over the life of the power plant.

Other Consolidated VIEs — Our other consolidated VIEs as of December 31, 2009, primarily consisted of monetized assets secured by financing for our PCF and PCF III subsidiaries. For each of these arrangements we were the primary beneficiary as we retained both the primary risk of loss and potential for reward associated with the assets of the subsidiary. These financings were fully repaid during the three months ended March 31, 2010 and are no longer VIEs under the current and prior accounting standards.

 
8
 


Unconsolidated VIEs and Investments

We have a 50% joint venture interest in Greenfield LP and a 50% equity interest in Whitby where we do not have the power to direct the most significant activities of these entities and therefore do not consolidate. Greenfield LP and Whitby are also VIEs. During 2009, we were not the primary beneficiary of OMEC and did not consolidate OMEC. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Condensed Balance Sheets as we exercise significant influence over their operating and financial policies. Our equity interest in the net (income) loss from OMEC for the three months ended March 31, 2009, and both Greenfield LP and Whitby for the three months ended March 31, 2010 and 2009, are recorded in income from unconsolidated investments in power plants.

At March 31, 2010, and December 31, 2009, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
   
Ownership
Interest as of
March 31, 2010
   
March 31, 2010
   
Our Maximum Exposure to Loss at March 31, 2010(2)
   
December 31, 2009
 
OMEC(1)
    100%     $     $     $ 144  
Greenfield LP
    50%       81       81       70  
Whitby
    50%       3       3        
Total investments
          $ 84     $ 84     $ 214  
__________
(1) 
OMEC was consolidated effective January 1, 2010. See Note 1.
 
(2)
Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. While we also could be responsible for our pro rata portion of debt, holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries. The debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. As of March 31, 2010, and December 31, 2009, equity method investee debt was approximately $507 million and $873 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $253 million and $624 million as of March 31, 2010 and December 31, 2009, respectively.
 
The following details our income and distributions from unconsolidated investments in power plants for the three months ended March 31, 2010 and 2009 (in millions):
 
 
Income from Unconsolidated
     
 
Investments in Power Plants
 
Distributions
 
 
2010
 
2009
 
2010
 
2009
 
OMEC(1)
      (10 )        
Greenfield LP
    (4 )     (5 )            
Whitby
    (3 )   (2 )           2  
Total
  (7 )   (17 )       2  
__________
(1)
OMEC was consolidated effective January 1, 2010. See Note 1.
 
Greenfield LP — Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,005 MW natural gas-fired power plant in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Greenfield LP holds an 18-year term loan in the amount of CAD $648 million. Borrowings under the project finance facility bear interest at Canadian LIBOR plus 1.125% or Canadian prime rate plus 0.125%. We contributed nil for the three months ended March 31, 2010 and 2009, as an additional investment in Greenfield LP.

Whitby — Represents our 50% equity interest in Whitby held by our Canadian subsidiaries.
 
Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center development project (a 775 MW natural gas-fired power plant located in California) from General Electric International, Inc. that may be exercised between years 7 and 14 after the start of commercial operation. General Electric International, Inc. holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met during year 15 after the start of commercial operation. We determined that we were not the primary beneficiary of the Inland Empire power and we do not consolidate it due to, but not limited to, the fact that General Electric International, Inc. has primary responsibility for construction and achieving commercial operation.

 
9
 

Significant Subsidiary — OMEC met the criteria of a significant subsidiary as defined under SEC guidelines during the three months ended March 31, 2009, based upon the relationship of our equity income from our investment in this subsidiary to our consolidated net income before income taxes.  See Note 1 for further information regarding the OMEC consolidation effective January 1, 2010. The Condensed Statements of Operations for OMEC for the three months ended March 31, 2009, are set forth below (in millions):
 
   
2009
 
Revenues
 
$
 
Operating expenses
   
1
 
Loss from operations
   
(1
)
Interest (income) expense(1)
   
(11
)
Other (income) expense, net
   
 
Net income
 
$
10
 
__________
(1)
Interest income is the result of unrealized mark-to-market gains from an interest rate swap contract.

5.   Comprehensive Income

Comprehensive income includes our net income (loss), unrealized gains and losses from derivative instruments, net of tax that qualify as cash flow hedges, our share of equity method investees’ OCI and the effects of foreign currency translation adjustments. We report AOCI on our Consolidated Condensed Balance Sheets. The table below details the components of our comprehensive income during the three months ended March 31, 2010 and 2009 (in millions):
 
   
2010
   
2009
 
Net income (loss)
  $ (48 )   $ 31  
Other comprehensive income (loss):
               
Gain on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
    101       202  
Reclassification adjustment for cash flow hedges realized in net income (loss)
    14       (67 )
Foreign currency translation gain (loss)
    2       (2 )
Income tax benefit
    14       13  
Comprehensive income
    83       177  
Add: Comprehensive loss attributable to the noncontrolling interest
    1       1  
Comprehensive income attributable to Calpine
  $ 84     $ 178  

6.  Debt

Our debt at March 31, 2010, and December 31, 2009, was as follows (in millions):
 
   
March 31, 2010
   
December 31, 2009
 
First Lien Credit Facility
  $ 4,625     $ 4,661  
First Lien Notes
    1,200       1,200  
Commodity Collateral Revolver
    100       100  
Project financing, notes payable and other
    2,406       2,289  
CCFC Notes
    960       959  
Capital lease obligations
    253       250  
Total debt
    9,544       9,459  
Less: Current maturities
    305       463  
Debt, net of current portion
  $ 9,239     $ 8,996  
 
First Lien Credit Facility — As of March 31, 2010, and December 31, 2009, our primary debt facility was our First Lien Credit Facility. Our First Lien Credit Facility includes an original $6.0 billion of senior secured term loans, a $1.0 billion senior secured revolving facility and, subject to market conditions, the ability to raise up to $2.0 billion of incremental term loans under an “accordion” provision available on a senior secured basis in order to refinance secured debt of subsidiaries. As of March 31, 2010, under our First Lien Credit Facility, we had approximately $4.6 billion outstanding under the term loans and $174 million of letters of credit issued against the revolver. Balances repaid under the senior secured term loans may not be reborrowed. Borrowings of term loans under our First Lien Credit Facility bear interest at a floating rate, at our option, of LIBOR plus 2.875% per annum or base rate plus 1.875% per annum. First Lien Credit Facility term loans require quarterly payments of principal equal to 0.25% of the original principal amount of First Lien Credit Facility term loans. Our First Lien Credit Facility matures on March 29, 2014.
 
 
 
10
 

 
The obligations under our First Lien Credit Facility are unconditionally guaranteed by certain of our direct and indirect domestic subsidiaries and are secured by a security interest in substantially all of the tangible and intangible assets of Calpine Corporation and certain of the guarantors. The obligations under our First Lien Credit Facility are also secured by a pledge of the equity interests of the direct subsidiaries of certain of the guarantors, subject to certain exceptions, including exceptions for equity interests in foreign subsidiaries, existing contractual prohibitions and prohibitions under other legal requirements. Our First Lien Credit Facility also requires compliance with financial covenants that include a maximum ratio of total net debt to Consolidated EBITDA (as defined in the First Lien Credit Facility), a minimum ratio of Consolidated EBITDA to cash interest expense, and a maximum ratio of total senior net debt to Consolidated EBITDA.

OMEC Debt — As further discussed in Note 1, we added approximately $375 million in project debt to our Consolidated Condensed Balance Sheet when we consolidated OMEC effective January 1, 2010. As of March 31, 2010 OMEC had approximately $372 million in project debt outstanding, which is included in the balance under the caption “Project financing, notes payable and other” in the table above. OMEC has a $377 million non-recourse project term loan which matures in April 2019. The term loan bears interest at LIBOR plus 1.25%.

Letter of Credit Facilities — The table below represents amounts outstanding under our letter of credit facilities as of March 31, 2010, and December 31, 2009 (in millions):
 
   
March 31, 2010
   
December 31, 2009
 
First Lien Credit Facility
  $ 174     $ 206  
Calpine Development Holdings, Inc.
    135       116  
Various project financing facilities
    113       90  
Total
  $ 422     $ 412  
 
Fair Value of Debt

We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative GAAP provisions of the fair value option for recording financial assets and financial liabilities at fair value on our Consolidated Condensed Financial Statements. We measured the fair value of our debt instruments as of March 31, 2010, and December 31, 2009, using market information including credit default swap rates and historical default information, quoted market prices or dealer quotes for the identical liability when traded as an asset and discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements. The following table details the fair values and carrying values of our debt instruments as of March 31, 2010, and December 31, 2009 (in millions):
 
   
March 31, 2010
   
December 31, 2009
 
   
Fair Value
   
Carrying Value
   
Fair Value
   
Carrying Value
 
First Lien Credit Facility
  $ 4,492     $ 4,625     $ 4,402     $ 4,661  
First Lien Notes
    1,170       1,200       1,138       1,200  
Commodity Collateral Revolver
    97       100       94       100  
Project financing, notes payable and other(1)
    1,914       1,979       1,808       1,840  
CCFC Notes
    1,015       960       1,030       959  
Total
  $ 8,688     $ 8,864     $ 8,472     $ 8,760  
__________
(1)   Excludes leases that are accounted for as failed sale-leaseback transactions under GAAP and included in our project financing, note payable and other balance.
 
7.  Fair Value Measurements

Derivatives — We enter into a variety of derivative instruments, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power, natural gas, and emission allowances as well as interest rate swaps.

Our level 1 fair value derivative instruments primarily consist of natural gas swaps, futures and options traded on the NYMEX.

Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from markets such as the Intercontinental Exchange and Bloomberg. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are primarily industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Our level 3 fair value derivative instruments primarily consist of our OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our or our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. In cases where there is no corroborating market information available to support significant model inputs, we initially use the transaction price as the best estimate of fair value. OTC options are valued using industry-standard models, including the Black-Scholes pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.

We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about risks and the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value; however, other qualitative assessments are used to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.

The primary factors affecting the fair value of our commodity derivative instruments at any point in time are the volume of open derivative positions (MMBtu and MWh); market price levels, principally for power and natural gas; our credit standing and that of our counterparties; and prevailing interest rates. Prices for power and natural gas are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.

The fair value of our derivatives includes consideration of the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.

Margin Deposits — Our margin deposits are cash and cash equivalents and are generally classified within level 1 of the fair value hierarchy as the amounts approximate fair value.

 
11
 


The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2010, and December 31, 2009, by level within the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
 
   
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2010
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
   
(in millions)
 
Assets:
                       
Cash equivalents(1)
  $ 1,316     $     $     $ 1,316  
Margin deposits(2)
    209                   209  
Commodity instruments:
                               
Commodity futures contracts
    1,696                   1,696  
Commodity forward contracts
          445       84       529  
Interest rate swaps
          10             10  
Total assets
  $ 3,221     $ 455     $ 84     $ 3,760  
                                 
Liabilities:
                               
Margin deposits held by us posted by our counterparties(2)
  $ 17     $     $     $ 17  
Commodity instruments:
                               
Commodity futures contracts
    1,666                   1,666  
Commodity forward contracts
          252       27       279  
Interest rate swaps
          388             388  
Total liabilities
  $ 1,683     $ 640     $ 27     $ 2,350  

   
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2009
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
   
(in millions)
 
Assets:
                       
Cash equivalents(1)
  $ 1,306     $     $     $ 1,306  
Margin deposits(2)
    413                   413  
Commodity instruments:
                               
Commodity futures contracts
    953                   953  
Commodity forward contracts
          204       71       275  
Interest rate swaps
          18             18  
Total assets
  $ 2,672     $ 222     $ 71     $ 2,965  
                                 
Liabilities:
                               
Margin deposits held by us posted by our counterparties(2)
  $ 9     $     $     $ 9  
Commodity instruments:
                               
Commodity futures contracts
    1,096                   1,096  
Commodity forward contracts
          91       33       124  
Interest rate swaps
          337             337  
Total liabilities
  $ 1,105     $ 428     $ 33     $ 1,566  
__________
(1)
Amounts represent cash equivalents invested in money market accounts and are included in cash and cash equivalents and restricted cash on our Consolidated Condensed Balance Sheets. As of March 31, 2010, and December 31, 2009, we had cash equivalents of $992 million and $770 million included in cash and cash equivalents and $324 million and $536 million included in restricted cash, respectively.
 
(2)
Margin deposits and margin deposits held by us posted by our counterparties represent cash collateral paid between our counterparties and us to support our derivative contracts.
 

 
12
 

 
No significant transfers between level 1 and level 2 occurred during the three months ended March 31, 2010 and 2009. The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the three months ended March 31, 2010 and 2009 (in millions):
 
   
2010
   
2009
 
Balance, beginning of period
  $ 38     $ 105  
Realized and unrealized gains (losses):
               
Included in net income (loss)(1)
    23       17  
Included in OCI
    8       18  
Purchases, issuances, sales and settlements:
               
Settlements
    (12 )     (13 )
Transfers into and/or out of level 3:(2)
               
Transfers into level 3
          (13 )
Balance, end of period
  $ 57     $ 114  
                 
Change in unrealized gains and (losses) relating to instruments still held at end of period(1)
  $ 23     $ 17  
__________
(1)
Includes $24 million and $6 million of gains recorded in operating revenues (for power contracts and Heat Rate swaps and options) and $(1) million of losses and $11 million of gains recorded in fuel and purchased energy expense (for natural gas contracts) for the three months ended March 31, 2010 and 2009, respectively, as shown on our Consolidated Condensed Statement of Operations.
 
(2)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no significant transfers into/out of level 3 during the three months ended March 31, 2010. For the three months ended March 31, 2009, we had $(13) million in losses transferred out of level 2 into level 3, due to market fluctuations in various power markets.
 
8.  Derivative Instruments
 
Types of Derivative Instruments and Volumetric Information

We execute forward physical and financial commodity purchase and sales agreements to hedge our exposure to underlying commodity risk. Through hedging and optimization activities, we purchase and sell forward natural gas and power in both the physical and financial markets.

Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas and other energy commodities. We use derivatives, including physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power, natural gas, and emission allowances to attempt to economically hedge a portion of the commodity price risk associated with our assets and thus maximize risk-adjusted returns. By entering into these transactions, we are able to economically hedge a portion of our spark spread at estimated generation and prevailing price levels.

Interest Rate Swaps — A significant portion of our debt is indexed to base rates, primarily LIBOR. We use interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates. These transactions primarily act as economic hedges for our interest cash flow.

As of March 31, 2010, the maximum length of our PPAs extends approximately 22 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 3 and 16 years, respectively.

As of March 31, 2010, and December 31, 2009, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
 
     
Notional Volumes
 
Derivative Instruments
   
March 31, 2010
 
December 31, 2009
 
Power (MWh)
   
(40
)
   
(52
)
Natural gas (MMBtu)
   
63
     
78
 
Interest rate swaps
 
$
7,683
   
$
7,324
 

 
13
 

Certain of our derivative instruments contain credit-contingent provisions that require us to maintain our current credit rating or higher from each of the major credit rating agencies. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that a counterparty would request full and immediate settlement or that any additional collateral posted as a result of a credit rating downgrade would be material. The aggregate fair value of our derivative liabilities with credit-contingent provisions as of March 31, 2010, was $31 million for which we have posted collateral of $16 million by posting margin deposits or granted additional first priority liens on the assets currently subject to first priority liens under our First Lien Credit Facility.

Accounting for Derivative Instruments

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. Revenues derived from these instruments that qualify for hedge accounting are recorded in the same period and in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.

Cash Flow Hedges — We report the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on commodity hedging instruments are included in unrealized mark-to-market gains and losses, and are recognized currently in earnings as a component of operating revenues (for power contracts), fuel and purchased energy expense (for natural gas contracts) and interest expense (for interest rate swaps). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the gain or loss associated with the hedge instrument remains deferred in OCI until such time as the forecasted transaction impacts earnings, or until it is determined that the forecasted transaction is probable of not occurring.

Fair Value Hedges — 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 or liability, or unrecognized firm commitment, are recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. 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 in earnings. If the hedging instrument is terminated or de-designated prior to the settlement of the hedged asset, liability or firm commitment, the carrying amount of the hedged item is adjusted by any gain or loss from the hedging instrument and remains until the hedged item is recognized in earnings. As of March 31, 2010 and December 31, 2009, we had no fair value hedges.

Derivatives Not Designated as Hedging Instruments — Along with our portfolio of hedging transactions, we enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset portfolio, but either do not qualify as hedges under hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Contracts commonly employed include agreements such as commodity futures, forwards, options, fixed for floating swaps and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options). Changes in fair value of derivatives not designated as hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts) and interest expense (for interest rate swaps).

 
14
 

Derivatives Included on Our Consolidated Condensed Balance Sheets

The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by hedge type and location at March 31, 2010 and December 31, 2009 (in millions):
 
   
March 31, 2010
 
Balance Sheet Presentation
 
Interest Rate
   
Commodity
       
 
Swaps
   
Instruments
   
Total
 
Current derivative assets
  $     $ 1,943     $ 1,943  
Long-term derivative assets
    10       282       292  
Total derivative assets
  $ 10     $ 2,225     $ 2,235  
Current derivative liabilities
  $ 192     $ 1,779     $ 1,971  
Long-term derivative liabilities
    196       166       362  
Total derivative liabilities
  $ 388     $ 1,945     $ 2,333  
Net derivative assets (liabilities)
  $ (378 )   $ 280     $ (98 )

   
December 31, 2009
 
Balance Sheet Presentation
 
Interest Rate
   
Commodity
       
 
Swaps
   
Instruments
   
Total
 
Current derivative assets
  $     $ 1,119     $ 1,119  
Long-term derivative assets
    18       109       127  
Total derivative assets
  $ 18     $ 1,228     $ 1,246  
Current derivative liabilities
  $ 202     $ 1,158     $ 1,360  
Long-term derivative liabilities
    135       62       197  
Total derivative liabilities
  $ 337     $ 1,220     $ 1,557  
Net derivative assets (liabilities)
  $ (319 )   $ 8     $ (311 )

   
March 31, 2010
 
   
Fair Value
   
Fair Value
 
   
of Derivative
   
of Derivative
 
   
Assets
   
Liabilities
 
Derivatives designated as cash flow hedging instruments:
           
Interest rate swaps
  $ 10     $ 357  
Commodity instruments
    421       163  
Total derivatives designated as cash flow hedging instruments
  $ 431     $ 520  
                 
Derivatives not designated as hedging instruments:
               
Interest rate swaps
  $     $ 31  
Commodity instruments
    1,804       1,782  
Total derivatives not designated as hedging instruments
  $ 1,804     $ 1,813  
Total derivatives
  $ 2,235     $ 2,333  

   
December 31, 2009
 
   
Fair Value
   
Fair Value
 
   
of Derivative
   
of Derivative
 
   
Assets
   
Liabilities
 
Derivatives designated as cash flow hedging instruments:
           
Interest rate swaps
  $ 18     $ 324  
Commodity instruments
    213       80  
Total derivatives designated as cash flow hedging instruments
  $ 231     $ 404  
                 
Derivatives not designated as hedging instruments:
               
Interest rate swaps
  $     $ 13  
Commodity instruments
    1,015       1,140  
Total derivatives not designated as hedging instruments
  $ 1,015     $ 1,153  
Total derivatives
  $ 1,246     $ 1,557  

 
15
 

Derivatives Included on Our Consolidated Condensed Statements of Operations, OCI and AOCI

Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our net income (loss).

The following tables detail the components of our total mark-to-market activity for both the net realized loss and the net unrealized gain (loss) recognized from our derivative instruments not designated as hedging instruments and where these components were recorded on our Consolidated Condensed Statements of Operations for the three months ended March 31, 2010 and 2009 (in millions):
 
   
2010
   
2009
 
Realized loss
           
Interest rate swaps
  $ (6 )   $ (4 )
Commodity instruments
    (7 )     (58 )
Total realized loss
  $ (13 )   $ (62 )
Unrealized gain (loss)(1)
               
Interest rate swaps
  $ (3 )   $ 1  
Commodity instruments
    112       125  
Total unrealized gain
  $ 109     $ 126  
Total mark-to-market activity
  $ 96     $ 64  
__________
(1)
Changes in unrealized gains and losses include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
   
2010
   
2009
 
Power contracts included in operating revenues
  $ (29 )   $ 40  
Natural gas contracts included in fuel and purchased energy expense
    134       27  
Interest rate swaps included in interest expense
    (9 )     (3 )
Total mark-to-market activity
  $ 96     $ 64  
 
 
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment on our Consolidated Condensed Statements of Operations, OCI and AOCI for the three and ended March 31, 2010 and 2009 (in millions):
 
 
2010
   
     
Gain (Loss)
 
Gain (Loss)
   
 
Gain (Loss)
 
Reclassified from
 
Reclassified from
   
 
Recognized in OCI
 
AOCI into Income
 
AOCI into Income
   
 
(Effective Portion)
 
(Effective Portion)
   
(Ineffective Portion)
 
Interest rate swaps
$ (11 ) $ (60 ) (1) $ (1)  (1)
Commodity instruments
  126     46   (2)   (1)  (2)
Total
$ 115   $ (14 )   $ (2)  

 
2009
 
     
Gain (Loss)
Gain (Loss)
 
 
Gain (Loss)
 
Reclassified from
Reclassified from
 
 
Recognized in OCI
 
AOCI into Income
AOCI into Income
 
 
(Effective Portion)
 
(Effective Portion)
   
(Ineffective Portion)
 
Interest rate swaps
$
7
 
$
(44
)
(1)
$
 
Commodity instruments
 
128
   
111
 
(2)
 
1
(2)
Total
$
135
 
$
67
   
$
1
 
__________
(1)
Included in interest expense on our Consolidated Condensed Statements of Operations.
 
(2)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.
 
Assuming constant March 31, 2010 power and natural gas prices and interest rates, we estimate that pre-tax net gains of $13 million would be reclassified from AOCI into earnings during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in natural gas and power prices as well as interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI to earnings (positive or negative) will be for the next 12 months.
 
 
 
 
16
 

 
9.  Use of Collateral

We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under our First Lien Credit Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under our First Lien Credit Facility and certain of our interest rate swap agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Credit Facility.

The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of March 31, 2010, and December 31, 2009 (in millions):
 
   
March 31, 2010
   
December 31, 2009
 
Margin deposits(1)
  $ 209     $ 413  
Natural gas and power prepayments
    34       34  
Total margin deposits and natural gas and power prepayments with our counterparties(2)
  $ 243     $ 447  
                 
Letters of credit issued
  $ 342     $ 353  
First priority liens under power and natural gas agreements(3)
           
First priority liens under interest rate swap agreements
    385       333  
Total letters of credit and first priority liens with our counterparties
  $ 727     $ 686  
                 
Margin deposits held by us posted by our counterparties(1)(4)
  $ 17     $ 9  
Letters of credit posted with us by our counterparties
    109       70  
Total margin deposits and letters of credit posted with us by our counterparties
  $ 126     $ 79  
__________
(1)
Balances are subject to master netting arrangements and presented on gross basis on our Consolidated Condensed Balance Sheets.
 
(2)
At March 31, 2010, and December 31, 2009, $222 million and $426 million were included in margin deposits and other prepaid expense, respectively, and $21 million were included in other assets at both March 31, 2010 and December 31, 2009 on our Consolidated Condensed Balance Sheets.
 
(3)
At March 31, 2010, and December 31, 2009, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $305 million and $123 million, respectively; therefore, there was no collateral exposure at March 31, 2010, or December 31, 2009.
 
(4)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
 
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.

10.  Income Taxes

For federal income tax reporting purposes, our consolidated GAAP financial reporting group is comprised primarily of two separate tax reporting groups, CCFC and its subsidiaries, which we refer to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we refer to as the Calpine group. In 2005, CCFCP issued the CCFCP Preferred Shares, which resulted in the deconsolidation of the CCFC group for income tax purposes. On July 1, 2009, the CCFCP Preferred Shares were redeemed; however, CCFCP continues to be a partnership and therefore, the CCFC group remains deconsolidated from Calpine Corporation for federal income tax reporting purposes. As of March 31, 2010, the CCFC group did not have a valuation allowance recorded against its deferred tax assets, whereas the Calpine group continued to have a valuation allowance. For the three months ended March 31, 2010 and 2009, we used the effective rate method to determine both the CCFC and Calpine groups’ tax provision; however, our income tax rates did not bear a customary relationship to statutory income tax rates primarily as a result of the impact of state income taxes, changes in unrecognized tax benefits, the Calpine group valuation allowance and intraperiod tax allocations discussed below. Our consolidated income tax expense and imputed tax rate was approximately $11 million and (31)% and approximately $9 million and 22% for the three months ended March 31, 2010 and 2009, respectively. Our income tax expense included intraperiod tax allocation expense of $14 million and $13 million for the three months ended March 31, 2010 and 2009, respectively with an offsetting tax benefit to OCI.
 
 
 
17
 
 
 
Valuation Allowance — GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. In prior periods, we provided a valuation allowance on certain federal, state and foreign tax jurisdiction deferred tax assets of the Calpine group 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. Projected future income from reversals of existing taxable temporary differences and tax planning strategies allowed a larger portion of the deferred tax assets to be offset against deferred tax liabilities resulting in a significant release of previously recorded valuation allowance in prior periods; however, we have not released any additional previously recorded valuation allowance in 2010.

Canadian Tax Audits — In September 2009, we received notice from the Canadian Revenue Authority, or CRA, of their intent to conduct a limited scope income tax audit on four of our Canadian subsidiaries for the tax years ending 2005 – 2008. We have timely responded to their request for information and received notice from the CRA that they have completed their audit of transactions within Canada and no changes were proposed. The CRA international audit division continues to review cross border transactions within the audit period. At this time, we are unable to determine the likelihood of a material adverse outcome.

We remain subject to other various audits and reviews by state taxing authorities; however, we do not expect these will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to U.S. Internal Revenue Service examination regardless of when the NOLs occurred. Due to significant NOLs, any adjustment of state returns or federal returns from 2006 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.

Unrecognized Tax Benefits and Liabilities — As of March 31, 2010, we had unrecognized tax benefits of $88 million. If recognized within the next 12 months, $41 million of our unrecognized tax benefits could impact the annual effective tax rate and $47 million related to deferred tax assets could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $18 million for income tax matters as of March 31, 2010. The amount of unrecognized tax benefits decreased by $10 million for the three months ended March 31, 2010, primarily as a result of $9 million related to a hedging position terminated for CCFC group. We believe it is reasonably possible that a decrease of approximately $1 million in unrecognized tax benefits could occur within the next 12 months primarily related to state tax liabilities and state interest and penalties.

NOL Carryforwards — Under federal income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the Internal Revenue Code. We experienced an ownership change on the Effective Date as a result of the cancellation of our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this ownership change and the resulting annual limitations are not expected to result in the expiration of our NOL carryforwards if we are able to generate sufficient future taxable income within the carryforward periods. If a subsequent ownership change were to occur as a result of future transactions in our stock, accompanied by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited. The Calpine group adjusted its NOL for prior periods through December 31, 2009, increasing it by approximately $183 million. These adjustments consisted of $49 million to reduce the NOL for excluded cancellation of debt income and a $232 million increase in prior period NOLs for development costs and construction in progress relating to abandoned projects.

To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock in the following circumstances: if, prior to February 1, 2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of approximately $8.6 billion (in each case, as defined in and calculated pursuant to our amended and restated certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to our equity for purposes of Section 382 of the Internal Revenue Code. We believe as of the filing of this Report, neither circumstance was met. While we don’t believe an ownership change of 25 percentage points has occurred, the change in ownership is only slightly less than 25%. Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the foregoing events were to occur together and our Board of Directors were to elect to impose them, they could become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from occurring.

 
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Should our Board of Directors elect to impose these restrictions, they shall have the authority and discretion to determine and establish the definitive terms of the transfer restrictions, provided that the transfer restrictions apply to purchases by owners of 5% or more of our common stock, including any owners who would become owners of 5% or more of our common stock via such purchase. The transfer restrictions will not apply to the disposition of shares provided they are not purchased by a 5% or more owner.

11.   Earnings (Loss) per Share

Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled and the issuance of 485 million new shares of reorganized Calpine Corporation common stock was authorized to resolve allowed unsecured claims. A portion of the 485 million authorized shares was immediately distributed, and the remainder was reserved for distribution to holders of certain disputed claims that, although allowed as of the Effective Date, are unresolved. To the extent that any of the reserved shares remain undistributed upon resolution of the disputed claims, such shares will not be returned to us but rather will be distributed pro rata to claimants with allowed claims to increase their recovery. Therefore, pursuant to our Plan of Reorganization, all 485 million shares ultimately will be distributed. Accordingly, although the reserved shares are not yet issued and outstanding, all conditions of distribution had been met for these reserved shares as of the Effective Date, and such shares are considered issued and are included in our calculation of weighted average shares outstanding. We also include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding.

Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the three months ending March 31, 2010 and 2009, are:
 
   
2010
   
2009
 
   
(shares in thousands)
 
Diluted weighted average shares calculation:
           
Weighted average shares outstanding (basic)
    485,921       485,362  
Share-based awards
          233  
Weighted average shares outstanding (diluted)
    485,921       485,595  
 
As we incurred a net loss for the three months ended March 31, 2010, diluted loss per share for the period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following potentially dilutive securities from our calculation of diluted earnings (loss) per common share for the three months ended March 31, 2010 and 2009.
 
   
2010
   
2009
 
   
(shares in thousands)
 
Share-based awards(1)
    14,264       13,241  
__________
(1)
Excluded from diluted weighted average shares as these share-based awards are anti-dilutive in accordance with the calculation under the treasury stock method prescribed by GAAP.
 
12.  Stock-Based Compensation

The Calpine Equity Incentive Plans were approved as part of our Plan of Reorganization. These plans are administered by the Compensation Committee of our Board of Directors and provide for the issuance of equity awards to all employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. Under the Equity Plan and the Director Plan there are 14,833,000 shares and 167,000 shares, respectively, of our common stock authorized for issuance to participants.

The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting options which vest over periods between one and five years, contain contractual terms of seven and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. Employment inducement options to purchase a total of 4,636,734 shares were granted outside of the Calpine Equity Incentive Plans in connection with our hiring of a new Chief Executive Officer and a new Chief Legal Officer in August 2008, and a new Chief Commercial Officer in September 2008; however, no grants of options or shares of restricted stock were made outside of the Calpine Equity Incentive Plans during the three months ended March 31, 2010 and 2009.

We use the Black-Scholes option-pricing model to estimate the fair value of our employee stock options on the grant date, which takes into account 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 as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views one three-year option grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of stock options granted. The first sub-grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year option grant with cliff vesting is viewed as one grant vesting over three years.
 
 
 
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Stock-based compensation expense recognized was $6 million and $13 million for the three months ended March 31, 2010 and 2009, respectively. We did not record any tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the three months ended March 31, 2010 and 2009. At March 31, 2010, there was unrecognized compensation cost of $28 million related to options and $23 million related to restricted stock, which is expected to be recognized over a weighted average period of 1.9 years for options and 2.3 years for restricted stock. We issue new shares from our reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.

A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2010, is as follows:
 
         
Weighted
     
         
Average
     
     
Weighted
 
Remaining
 
Aggregate
 
 
Number of
 
Average
 
Term
 
Intrinsic Value
 
 
Options
 
Exercise Price
 
(in years)
 
(in millions)
 
Outstanding – December 31, 2009
13,232,519
 
$
19.09
 
6.6
 
$
2
 
Granted
1,005,081
 
$
11.24
           
Exercised
810
 
$
8.84
           
Forfeited
63,060
 
$
14.84
           
Expired
59,414
 
$
17.22
           
Outstanding – March 31, 2010
14,114,316
 
$
18.56
 
6.6
 
$
3
 
Exercisable – March 31, 2010
4,756,433
 
$
18.59
 
6.8
 
$
 
Vested and expected to vest – March 31, 2010
13,865,500
 
$
18.67
 
6.5
 
$
3
 

The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the three months ended March 31, 2010. There were no employee stock options exercised during the three months ended March 31, 2009.

The fair value of options granted during the three months ended March 31, 2010 and 2009, was determined on the grant date using the Black-Scholes pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
   
2010
   
2009
 
Expected term (in years)(1)
    6.5       6.0  
Risk-free interest rate(2)
    3.1 %     2.3 %
Expected volatility(3)
    35 %     73 %
Dividend yield(4)
           
Weighted average grant-date fair value (per option)
  $ 4.64     $ 5.40  
__________
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.
 
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
 
(3)
Volatility calculated using the implied volatility of our exchange traded options.
 
(4)
We are currently prohibited under our First Lien Credit Facility and certain of our other debt agreements from paying any cash dividends on our common stock.
 

 
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No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2010, is as follows:
 
       
Weighted
 
   
Number of
 
Average
 
   
Restricted
 
Grant-Date
 
   
Stock Awards
 
Fair Value
 
Nonvested – December 31, 2009
 
2,046,599
 
$
11.95
 
Granted
 
1,418,129
 
$
11.24
 
Forfeited