XNYS:CPN Calpine Corp Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
____________________
Form 10-Q
(Mark One)
[X]
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
For the quarterly period ended June 30, 2012
 
 
 
 
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) 830-2000
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.    Yes [X]    No [    ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 [X]    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 definitions of “large accelerated filer, “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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 [    ]    No [X]
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 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.    Yes [X]    No [    ]
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 466,616,007 shares of common stock, par value $0.001, were outstanding as of July 24, 2012.
 




CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2012
INDEX
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i



DEFINITIONS
As used in this Quarterly Report for the quarter ended June 30, 2012 (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
2011 Form 10-K
 
Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 9, 2012
 
 
 
2017 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.25% 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

 
 
 
2019 First Lien Notes
 
The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010

 
 
 
2020 First Lien Notes
 
The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010
 
 
 
2021 First Lien Notes
 
The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010
 
 
 
2023 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011
 
 
 
AB 32
 
California Assembly Bill 32
 
 
 
Adjusted EBITDA
 
EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) unrealized gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) stock-based compensation expense, (g) gains or losses on sales, dispositions or retirements of assets, (h) non-cash gains and losses from foreign currency translations, (i) gains or losses on the repurchase or extinguishment of debt and (j) 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
 
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, excluding peakers, during the period by (ii) the total hours in the period
 
 
 
Btu
 
British thermal unit(s), a measure of heat content
 
 
 
CAA
 
Federal Clean Air Act, U.S. Code Title 42, Chapter 85
 
 
 
CAIR
 
Clean Air Interstate Rule
 
 
 
CAISO
 
California Independent System Operator
 
 
 
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
 
 
 

ii



ABBREVIATION
 
DEFINITION
Cap-and-trade
 
A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
 
 
 
CARB
 
California Air Resources Board
 
 
 
CCFC
 
Calpine Construction Finance Company, L.P., an indirect, wholly owned subsidiary
 
 
 
CCFC Finance
 
CCFC Finance Corp.
 
 
 
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

 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly owned subsidiary
 
 
 
CFTC
 
U.S. Commodities Futures Trading Commission
 
 
 
Chapter 11
 
Chapter 11 of the U.S. Bankruptcy Code
 
 
 
CO2
 
Carbon dioxide
 
 
 
COD
 
Commercial operations date
 
 
 
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 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 including natural gas transactions hedging future power sales 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 physical natural gas, capacity revenue, REC revenue, sales of surplus emissions allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales 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 physical natural gas, capacity revenue, REC revenue, sales of surplus emissions 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

 
 
 
Corporate Revolving Facility
 
The $1.0 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and the other parties thereto
 
 
 
CPUC
 
California Public Utilities Commission
 
 
 
Creed
 
Creed Energy Center, LLC
 
 
 


iii



ABBREVIATION
 
DEFINITION
Director Plan
 
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
 
 
 
Dodd-Frank Act
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
 
 
 
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
 
Calpine Corporation's market capitalization calculated using 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
 
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
 
 
 
ERCOT
 
Electric Reliability Council of Texas
 
 
 
Exchange Act
 
U.S. Securities Exchange Act of 1934, as amended
 
 
 
FASB
 
Financial Accounting Standards Board
 
 
 
FDIC
 
U.S. Federal Deposit Insurance Corporation
 
 
 
FERC
 
U.S. Federal Energy Regulatory Commission
 
 
 
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
 
Collectively, the 2017 First Lien Notes, the 2019 First Lien Notes, the 2020 First Lien Notes, the 2021 First Lien Notes and the 2023 First Lien Notes

 
 
 
First Lien Term Loans
 
Collectively, the $1.3 billion first lien senior secured term loans dated March 9, 2011 and the $360 million first lien senior secured term loans dated June 17, 2011
 
 
 
GE
 
General Electric International, Inc.
 
 
 
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(s)
 
Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
 
 
 
Goose Haven
 
Goose Haven Energy Center, LLC
 
 
 
Greenfield LP
 
Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
 
 
 
Heat Rate(s)
 
A measure of the amount of fuel required to produce a unit of power
 
 
 
IOUs
 
Investor Owned Utilities
 
 
 

iv



ABBREVIATION
 
DEFINITION
IRC
 
Internal Revenue Code
 
 
 
ISO(s)
 
Independent System Operator(s)
 
 
 
KWh
 
Kilowatt hour(s), a measure of power produced, purchased or sold
 
 
 
LIBOR
 
London Inter-Bank Offered Rate
 
 
 
Los Esteros Project Debt
 
Credit Agreement, dated August 23, 2011, between Los Esteros Critical Energy Facility, LLC, as borrower, and the lenders named therein
 
 
 
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, purchased or sold
 
 
 
NDH
 
New Development Holdings, LLC, an indirect, wholly owned subsidiary
 
 
 
NDH Project Debt
 
The $1.3 billion senior secured term loan facility and the $100 million revolving credit facility issued on July 1, 2010, under the credit agreement, dated as of June 8, 2010, among NDH, as borrower, Credit Suisse AG, as administrative agent, collateral agent, issuing bank and syndication agent, Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as joint book-runners and joint lead arrangers, Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company Americas, as co-documentation agents and the lenders party thereto repaid on March 9, 2011
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
NOX
 
Nitrogen oxides
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
OCI
 
Other Comprehensive Income
 
 
 
OTC
 
Over-the-Counter
 
 
 
PG&E
 
Pacific Gas & Electric Company
 
 
 
PJM
 
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia

 
 
 
Plan of Reorganization
 
Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the 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
 
 
 


v



ABBREVIATION
 
DEFINITION
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
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
PUHCA 2005
 
U.S. Public Utility Holding Company Act of 2005
 
 
 
PURPA
 
U.S. Public Utility Regulatory Policies Act of 1978
 
 
 
QF(s)
 
Qualifying facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from the books and records requirement of PUHCA 2005 and grants certain other benefits to the QF
 
 
 
REC(s)
 
Renewable energy credit(s)
 
 
 
Reserve margin(s)
 
The measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region
 
 
 
RGGI
 
Regional Greenhouse Gas Initiative
 
 
 
Risk Management Policy
 
Calpine's policy applicable to all employees, contractors, representatives and agents which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
 
 
 
RPS
 
Renewable Portfolio Standards
 
 
 
RTO(s)
 
Regional Transmission Organization(s)
 
 
 
Russell City Project Debt
 
Credit Agreement dated June 24, 2011, between Russell City Energy Company, LLC, as borrower, and the lenders named therein

 
 
 
SEC
 
U.S. Securities and Exchange Commission
 
 
 
Securities Act
 
U.S. Securities Act of 1933, as amended
 
 
 
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
 
 
 
U.S. Bankruptcy Court
 
U.S. Bankruptcy Court for the Southern District of New York
 
 
 
U.S. Debtor(s)
 
Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matter was jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL) and was dismissed on December 19, 2011
 
 
 
U.S. GAAP
 
Generally accepted accounting principles in the U.S.
 
 
 

vi



ABBREVIATION
 
DEFINITION
VAR
 
Value-at-risk
 
 
 
VIE(s)
 
Variable interest entity(ies)
 
 
 
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

 
 
 
WP&L
 
Wisconsin Power and Light Company, a wholly owned subsidiary of Alliant Energy Corporation
 
 
 
York Energy Center
 
565 MW dual fuel, combined-cycle generation power plant (formerly known as the Delta Project) located in Peach Bottom Township, Pennsylvania which achieved COD on March 2, 2011

 

vii



Forward-Looking Statements

In addition to historical information, this Quarterly Report on Form 10-Q (this “Report”) contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this report, including without limitation, the “Management's Discussion and Analysis” section. 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:
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, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability to hedge risks;
Laws, regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;
Our ability to manage our liquidity needs and to comply with covenants under our First Lien Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Notes and other existing financing obligations;
Risks associated with the continued economic and financial conditions affecting certain countries in Europe including financial institutions located within those countries and their ability to fund their financial commitments;
Risks associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
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;
Competition, including risks associated with marketing and selling power in the evolving energy markets;
The expiration or early termination of our PPAs and the related results on revenues;
Future capacity revenues may not occur at expected levels;
Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;
Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power;
Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
Our ability to attract, motivate and retain key employees;
Present and possible future claims, litigation and enforcement actions; and
Other risks identified in this Report and in our 2011 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.

viii



Where You Can Find Other Information
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. 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.

ix



PART I — FINANCIAL INFORMATION
Item 1.
Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)

 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2012

2011
 
2012
 
2011
 
 
(in millions, except share and per share amounts)
Operating revenues
 
$
879

 
$
1,633

 
$
2,115

 
$
3,132

Operating expenses:
 
 
 
 
 
 
 
 
Fuel and purchased energy expense
 
612

 
1,000

 
1,244

 
2,069

Plant operating expense
 
271

 
261

 
492

 
499

Depreciation and amortization expense
 
138

 
131

 
278

 
262

Sales, general and other administrative expense
 
35

 
34

 
68

 
66

Other operating expenses
 
21

 
22

 
45

 
42

Total operating expenses
 
1,077

 
1,448

 
2,127

 
2,938

(Income) loss from unconsolidated investments in power plants
 
(5
)
 
2

 
(14
)
 
(7
)
Income (loss) from operations
 
(193
)
 
183

 
2

 
201

Interest expense
 
184

 
192

 
369

 
383

Loss on interest rate derivatives
 

 
37

 
14

 
146

Interest (income)
 
(2
)
 
(2
)
 
(5
)
 
(5
)
Debt extinguishment costs
 

 
5

 
12

 
98

Other (income) expense, net
 
6

 
3

 
8

 
10

Loss before income taxes
 
(381
)
 
(52
)
 
(396
)
 
(431
)
Income tax expense (benefit)
 
(52
)
 
18

 
(58
)
 
(65
)
Net loss
 
(329
)
 
(70
)
 
(338
)
 
(366
)
Net income attributable to the noncontrolling interest
 

 

 

 
(1
)
Net loss attributable to Calpine
 
$
(329
)
 
$
(70
)
 
$
(338
)
 
$
(367
)
 
 
 
 
 
 
 
 
 
Basic and diluted loss per common share attributable to Calpine:
 
 
 
 
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
 
471,444

 
486,411

 
474,775

 
486,334

Net loss per common share attributable to Calpine — basic and diluted
 
$
(0.69
)
 
$
(0.14
)
 
$
(0.71
)
 
$
(0.75
)
 
 
 
 
 
 
 
 
 

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


1



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE LOSS
(Unaudited)

 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2012
 
2011
 
2012
 
2011
 
 
(in millions)
Net loss
 
$
(329
)
 
$
(70
)
 
$
(338
)
 
$
(366
)
Cash flow hedging activities:
 
 
 
 
 
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss
 
(44
)
 
(17
)
 
(34
)
 
14

Reclassification adjustment for (gain) loss on cash flow hedges realized in net loss
 
(4
)
 
(31
)
 
(14
)
 
44

Foreign currency translation loss
 
(4
)
 
(1
)
 
(1
)
 

Income tax (expense) benefit
 
2

 
18

 
4

 
(16
)
Other comprehensive income (loss)
 
(50
)
 
(31
)
 
(45
)
 
42

Comprehensive loss
 
(379
)
 
(101
)
 
(383
)
 
(324
)
Comprehensive (income) attributable to the noncontrolling interest
 

 

 

 
(1
)
Comprehensive loss attributable to Calpine
 
$
(379
)
 
$
(101
)
 
$
(383
)
 
$
(325
)

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


2



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

 
 
June 30,
 
December 31,
 
 
2012
 
2011
 
 
(in millions, except share and per share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents ($169 and $285 attributable to VIEs)
 
$
587

 
$
1,252

Accounts receivable, net of allowance of $14 and $13
 
532

 
598

Margin deposits and other prepaid expense
 
305

 
193

Restricted cash, current ($85 and $57 attributable to VIEs)
 
124

 
139

Derivative assets, current
 
1,049

 
1,051

Inventory and other current assets
 
337

 
329

Total current assets
 
2,934

 
3,562

Property, plant and equipment, net ($4,473 and $4,313 attributable to VIEs)
 
13,109

 
13,019

Restricted cash, net of current portion ($50 and $53 attributable to VIEs)
 
51

 
55

Investments
 
76

 
80

Long-term derivative assets
 
158

 
113

Other assets
 
559

 
542

Total assets
 
$
16,887

 
$
17,371

LIABILITIES & STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
353

 
$
435

Accrued interest payable ($25 and $19 attributable to VIEs)
 
200

 
200

Debt, current portion ($39 and $41 attributable to VIEs)
 
103

 
104

Derivative liabilities, current
 
1,243

 
1,144

Other current liabilities
 
274

 
279

Total current liabilities
 
2,173

 
2,162

Debt, net of current portion ($2,731 and $2,522 attributable to VIEs)
 
10,488

 
10,321

Long-term derivative liabilities
 
276

 
279

Other long-term liabilities
 
247

 
245

Total liabilities
 
13,184

 
13,007

 
 
 
 
 
Commitments and contingencies (see Note 10)
 

 

Stockholders’ equity:
 
 
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding
 

 

Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 492,024,794 and 490,468,815 shares issued, respectively, and 466,615,007 and 481,743,738 shares outstanding, respectively
 
1

 
1

Treasury stock, at cost, 25,409,787 and 8,725,077 shares, respectively
 
(420
)
 
(125
)
Additional paid-in capital
 
12,320

 
12,305

Accumulated deficit
 
(8,037
)
 
(7,699
)
Accumulated other comprehensive loss
 
(223
)
 
(178
)
Total Calpine stockholders’ equity
 
3,641

 
4,304

Noncontrolling interest
 
62

 
60

Total stockholders’ equity
 
3,703

 
4,364

Total liabilities and stockholders’ equity
 
$
16,887

 
$
17,371


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

3



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

 
 
Six Months Ended June 30,
 
 
2012
 
2011
 
 
(in millions)
Cash flows from operating activities:
 
 
 
 
Net loss
 
$
(338
)
 
$
(366
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
 
Depreciation and amortization expense(1)
 
299

 
279

Debt extinguishment costs
 

 
85

Deferred income taxes
 
(31
)
 
(90
)
Loss on disposition of assets
 
4

 
9

Unrealized mark-to-market activities, net
 
119

 
77

(Income) from unconsolidated investments in power plants
 
(14
)
 
(7
)
Return on unconsolidated investments in power plants
 
16

 
6

Stock-based compensation expense
 
13

 
12

Other
 
1

 
5

Change in operating assets and liabilities:
 
 
 
 
Accounts receivable
 
63

 
(68
)
Derivative instruments, net
 
(111
)
 
(29
)
Other assets
 
(122
)
 
58

Accounts payable and accrued expenses
 
(86
)
 
166

Settlement of non-hedging interest rate swaps
 
156

 
103

Other liabilities
 
(1
)
 
(1
)
Net cash provided by (used in) operating activities
 
(32
)
 
239

Cash flows from investing activities:
 
 
 
 
Purchases of property, plant and equipment
 
(369
)
 
(341
)
Settlement of non-hedging interest rate swaps
 
(156
)
 
(103
)
Decrease in restricted cash
 
19

 
30

Purchases of deferred transmission credits
 
(12
)
 
(8
)
Other
 
5

 
1

Net cash used in investing activities
 
(513
)
 
(421
)
Cash flows from financing activities:
 
 
 
 
Repayment of Term Loans
 
(8
)
 

Borrowings under First Lien Term Loans
 

 
1,657

Repayments on NDH Project Debt
 

 
(1,283
)
Issuance of 2023 First Lien Notes
 

 
1,200

Repayments on First Lien Credit Facility
 

 
(1,187
)
Borrowings from project financing, notes payable and other
 
226

 
69

Repayments of project financing, notes payable and other
 
(46
)
 
(419
)
Capital contributions from noncontrolling interest holder
 

 
34

Financing costs
 
(5
)
 
(67
)
Stock repurchases
 
(290
)
 

Other
 
3

 
(2
)
Net cash provided by (used in) financing activities
 
(120
)
 
2

Net decrease in cash and cash equivalents
 
(665
)
 
(180
)
Cash and cash equivalents, beginning of period
 
1,252

 
1,327

Cash and cash equivalents, end of period
 
$
587

 
$
1,147


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


4



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)
(Unaudited)

 
 
Six Months Ended June 30,
 
 
2012
 
2011
 
 
(in millions)
Cash paid during the period for:
 
 
 
 
Interest, net of amounts capitalized
 
$
352

 
$
292

Income taxes
 
$
13

 
$
12

 
 
 
 
 
Supplemental disclosure of non-cash investing activities:
 
 
 
 
Change in capital expenditures included in accounts payable
 
$
3

 
$
21

____________
(1)
Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations.
The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.


5



CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 2012
(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 primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We engage in the purchase of natural gas and fuel oil 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 physical and financial contracts 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 normal, recurring 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 U.S. 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, 2011, included in our 2011 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, intraperiod provisions for income taxes computed in accordance with U.S. GAAP, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. 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.
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 June 30, 2012 and December 31, 2011, we had cash and cash equivalents of $178 million and $306 million, respectively, that were subject to such project finance facilities and lease agreements.
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 is 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 June 30, 2012 and December 31, 2011 (in millions):

 
June 30, 2012
 
December 31, 2011
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
16

 
$
42

 
$
58

 
$
11

 
$
42

 
$
53

Rent reserve
7

 

 
7

 

 

 

Construction/major maintenance
47

 
2

 
49

 
33

 
10

 
43

Security/project/insurance
54

 
5

 
59

 
79

 

 
79

Other

 
2

 
2

 
16

 
3

 
19

Total
$
124

 
$
51

 
$
175

 
$
139

 
$
55

 
$
194


6



___________
(1)
At both June 30, 2012 and December 31, 2011, amounts restricted for debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.
Inventory — At June 30, 2012 and December 31, 2011, we had inventory of $262 million and $294 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, 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 is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Property, Plant and Equipment, Net — At June 30, 2012 and December 31, 2011, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
June 30, 2012
 
December 31, 2011
Buildings, machinery and equipment
$
15,154

 
$
15,074

Geothermal properties
1,199

 
1,163

Other
157

 
156

 
16,510

 
16,393

Less: Accumulated depreciation
4,405

 
4,158

 
12,105

 
12,235

Land
90

 
91

Construction in progress
914

 
693

Property, plant and equipment, net
$
13,109

 
$
13,019

Capitalized Interest — The total amount of interest capitalized was $9 million and $4 million for the three months ended June 30, 2012 and 2011, respectively, and $17 million and $11 million for the six months ended June 30, 2012 and 2011, respectively.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements related to power plants under construction, at June 30, 2012, are as follows (in millions):
2012
$
285

2013
527

2014
465

2015
481

2016
396

Thereafter
2,312

Total
$
4,466

 
 
Treasury Stock — During the six months ended June 30, 2012, we repurchased common stock with a value of $290 million under our share repurchase program and withheld shares with a value of $5 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees under the Equity Plan.
New Accounting Standards and Disclosure Requirements
Fair Value Measurement — In May 2011, the FASB issued Accounting Standards Update 2011-04, “Fair Value Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating to fair value measurements. The update stems from the FASB and the International Accounting Standards Board project to develop common requirements for measuring fair value and for disclosing information about fair value measurements. The update did not impact any of our fair value measurements but did require disclosure of the following:
quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy;

7



for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and
the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.
The new requirements relating to fair value measurements are prospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption prohibited. We adopted all of the requirements related to this update at January 1, 2012. Since this update did not impact any of our fair value measurements and only required additional disclosures, adoption of this standard did not have a material impact on our results of operations, cash flows or financial condition.
Disclosures about Offsetting Assets and Liabilities — In December 2011, the FASB issued Accounting Standards Update 2011-11, “Balance Sheet - Disclosures about Offsetting Assets and Liabilities” to enhance disclosure requirements relating to the offsetting of assets and liabilities on an entity's balance sheet. The update requires enhanced disclosures regarding assets and liabilities that are presented net or gross in the statement of financial position when the right of offset exists, or that are subject to an enforceable master netting arrangement. The new disclosure requirements relating to this update are retrospective and effective for annual and interim periods beginning on or after January 1, 2013. The update only requires additional disclosures, as such, we do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.
2.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the six months ended June 30, 2012. See Note 5 in our 2011 Form 10-K for further information regarding our VIEs.
Riverside Energy Center
Our 603 MW Riverside Energy Center has a PPA that provides WP&L an option to purchase the power plant and plant-related assets for approximately $392 million upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase Riverside Energy Center, LLC, one of our VIEs which owns Riverside Energy Center. The sale is expected to close in December 2012 and is subject to federal regulatory approval. The assets being disposed of did not meet the criteria for classification as held for sale under U.S. GAAP, and we do not expect any gain (loss) on sale. At June 30, 2012, Riverside Energy Center, LLC had total assets of $422 million and total liabilities of $5 million.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 10,500 MW and 11,391 MW, at June 30, 2012 and December 31, 2011, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among 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 provided support to these VIEs in the form of cash and other contributions other than amounts contractually required of nil during both the three months ended June 30, 2012 and 2011, and nil and $72 million during the six months ended June 30, 2012 and 2011, respectively.
U.S. GAAP requires separate disclosure on the face of our Consolidated Condensed Balance Sheets 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. In determining which assets of our VIEs meet the separate disclosure criteria, we consider this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider whether this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.

8



Unconsolidated VIEs and Investments
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. 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. At June 30, 2012 and December 31, 2011, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of June 30, 2012
 
June 30, 2012
 
December 31, 2011
Greenfield LP
50%
 
$
69

 
$
72

Whitby
50%
 
7

 
8

Total investments
 
 
$
76

 
$
80

Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At June 30, 2012 and December 31, 2011, equity method investee debt was approximately $448 million and $462 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $224 million and $231 million at June 30, 2012 and December 31, 2011, respectively.
Our equity interest in the net income (loss) from Greenfield LP and Whitby for the three and six months ended June 30, 2012 and 2011 is recorded in (income) loss from unconsolidated investments in power plants. The following table sets forth details of our (income) loss from unconsolidated investments in power plants for the periods indicated (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Greenfield LP
$
(2
)
 
$
4

 
$
(8
)
 
$
(1
)
Whitby
(3
)
 
(2
)
 
(6
)
 
(6
)
Total
$
(5
)
 
$
2

 
$
(14
)
 
$
(7
)

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 1,038 MW natural gas-fired, combined-cycle power plant located 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%. Distributions from Greenfield LP were $9 million during both the three and six months ended June 30, 2012, and $2 million during both the three and six months ended June 30, 2011.
Whitby — Whitby is a limited partnership between certain subsidiaries of ours and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby. Distributions from Whitby were $7 million during both the three and six months ended June 30, 2012, and $4 million during both the three and six months ended June 30, 2011.
Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California which achieved COD on May 3, 2010) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.

9



3.
Debt
At June 30, 2012 and December 31, 2011, our debt was as follows (in millions):
 
June 30, 2012

December 31, 2011
First Lien Notes
$
5,892

 
$
5,892

Project financing, notes payable and other
1,865

 
1,691

First Lien Term Loans
1,638

 
1,646

CCFC Notes
975

 
972

Capital lease obligations
221

 
224

Total debt
10,591

 
10,425

Less: Current maturities
103

 
104

Debt, net of current portion
$
10,488

 
$
10,321

First Lien Notes
Our First Lien Notes are summarized in the table below (in millions):
 
June 30, 2012
 
December 31, 2011
2017 First Lien Notes
$
1,200

 
$
1,200

2019 First Lien Notes
400

 
400

2020 First Lien Notes
1,092

 
1,092

2021 First Lien Notes
2,000

 
2,000

2023 First Lien Notes
1,200

 
1,200

Total First Lien Notes
$
5,892

 
$
5,892

Our First Lien Notes are secured equally and ratably with indebtedness incurred under our Corporate Revolving Facility and First Lien Term Loans, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors' existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors' other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes.
Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:
incur or guarantee additional first lien indebtedness;
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
enter into sale and leaseback transactions;
create or incur liens; and
consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.
First Lien Term Loans
Our First Lien Term Loans provide for a senior secured term loan facility and bear interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the First Lien Term Loans credit agreements), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%.
An aggregate amount equal to 0.25% of the aggregate principal amount of the First Lien Term Loans will be payable at the end of each quarter with the remaining balance payable on the maturity date (April 1, 2018). We may elect from time to time to convert all or a portion of the First Lien Term Loans from initial LIBOR rate loans to base rate loans or vice versa. In addition, we may at any time, and from time to time, prepay the First Lien Term Loans, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent. We may elect to extend the maturity of any term loans under the First Lien

10



Term Loans, in whole or in part subject to approval from those lenders holding such term loans. The First Lien Term Loans are subject to certain qualifications and exceptions, similar to our First Lien Notes.
If a change of control triggering event occurs, the Company shall notify the administrative agent in writing and shall make an offer to prepay the entire principal amount of the First Lien Term Loans outstanding within thirty days after the date of such change of control triggering event.
In connection with the First Lien Term Loans, the Company and its subsidiaries (subject to certain exceptions) have made certain representations and warranties and are required to comply with various affirmative and negative covenants. The First Lien Term Loans are subject to customary events of default included in financing transactions, including, among others, failure to make payments when due, certain defaults under other material indebtedness, breach of certain covenants, breach of certain representations and warranties, involuntary or voluntary bankruptcy, and material judgments. If an event of default arises from certain events of bankruptcy or insolvency, all amounts outstanding under the First Lien Term Loans will become due and payable immediately without further action or notice. If other events of default arise (as defined in the Credit Agreement) and are continuing, the lenders holding more than 50% of the outstanding First Lien Term Loans (as defined in the Credit Agreement) may declare all the First Lien Term Loans outstanding to be due and payable immediately.
Russell City Project Debt 
On June 24, 2011, we, through our indirect, partially owned subsidiary Russell City Energy Company, LLC, closed on our approximately $845 million Russell City Project Debt to finance construction of Russell City Energy Center, a 619 MW natural gas-fired, combined-cycle power plant under construction located in Hayward, California. The Russell City Project Debt is comprised of a $700 million construction loan facility, an approximately $77 million project letter of credit facility and a $68 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At June 30, 2012, approximately $414 million had been drawn under the construction loan and approximately $61 million of letters of credit were issued under the letter of credit facilities. Calpine's pro rata share would be 75% and the pro rata share related to the noncontrolling interest would be 25%.
Los Esteros Project Debt
On August 23, 2011, we, through our indirect, wholly owned subsidiary Los Esteros Critical Energy Facility, LLC, closed on our $373 million Los Esteros Project Debt to finance the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle power plant to a 309 MW combined-cycle generation power plant. The upgrade will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. The Los Esteros Project Debt is comprised of a $305 million construction loan facility, an approximately $38 million project letter of credit facility and an approximately $30 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At June 30, 2012, approximately $139 million had been drawn under the construction loan and approximately $30 million of letters of credit were issued under the letter of credit facilities.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
Corporate Revolving Facility
$
385

 
$
440

CDHI
256

 
193

Various project financing facilities
130

 
130

Total
$
771

 
$
763

The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 2.00% to 2.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers' Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 3.00% to 3.25%. Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of

11



the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.50% to 0.75% on the unused amount of commitments under the Corporate Revolving Facility.
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures December 10, 2015.
The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors' other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.
CDHI
We also have a letter of credit facility related to CDHI. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.
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 U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The following table details the fair values and carrying values of our debt instruments at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
6,340

 
$
5,892

 
$
6,219

 
$
5,892

Project financing, notes payable and other(1)
1,667

 
1,705

 
1,467

 
1,504

First Lien Term Loans
1,630

 
1,638

 
1,615

 
1,646

CCFC Notes
1,085

 
975

 
1,070

 
972

Total
$
10,722

 
$
10,210

 
$
10,371

 
$
10,014

____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

On January 1, 2012, we adopted Accounting Standards Update 2011-04 "Fair Value Measurement" which requires the categorization by level of the fair value hierarchy for items not measured at fair value on our Consolidated Condensed Balance Sheets but for which fair value is required to be disclosed. We measure the fair value of our First Lien Notes, First Lien Term Loans and CCFC Notes using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.

12



4.
Assets and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. 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. Our cash equivalents are classified within level 1 of the fair value hierarchy.
Margin Deposits and Margin Deposits Held by Us Posted by Our Counterparties — Margin deposits and margin deposits held by us posted by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits held by us posted by our counterparties are generally cash and cash equivalents and are classified within level 1 of the fair value hierarchy.
Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); market price levels, primarily for power and natural gas; our credit standing and that of our counterparties; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
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 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. We use other qualitative assessments 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 fair value of our derivatives includes consideration of our credit standing, 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.
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 market sources such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. 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 may consist of 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 option-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.
At June 30, 2012, the derivative instruments classified as level 3 primarily included longer term OTC traded commodity contracts extending through 2014. These contracts are classified as level 3 as the contract terms exceed the period for which liquid market rate information is available. As such, the fair value of each contract incorporates extrapolation assumptions made in the

13



determination of the market price for future delivery periods in which applicable commodity prices were either not observable or lacked corroborative market data. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices, however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2012.
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
June 30, 2012
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input(s)
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
(8
)
 
Discounted cash flow
 
Market price (per MWh)
 
$19.30 — $160.75/MWh
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, 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 our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels.
 
Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2012
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
723

 
$

 
$

 
$
723

Margin deposits
262

 

 

 
262

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
923

 

 

 
923

Commodity forward contracts(2)

 
252

 
26

 
278

Interest rate swaps

 
6

 

 
6

Total assets
$
1,908

 
$
258

 
$
26

 
$
2,192

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
45

 
$

 
$

 
$
45

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
745

 

 

 
745

Commodity forward contracts(2)

 
541

 
36

 
577

Interest rate swaps

 
197

 

 
197

Total liabilities
$
790

 
$
738

 
$
36

 
$
1,564



14



 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2011
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,415

 
$

 
$

 
$
1,415

Margin deposits
140

 

 

 
140

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,043

 

 

 
1,043

Commodity forward contracts(2)

 
74

 
37

 
111

Interest rate swaps

 
10

 

 
10

Total assets
$
2,598

 
$
84

 
$
37

 
$
2,719

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
34

 
$

 
$

 
$
34

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
899

 

 

 
899

Commodity forward contracts(2)

 
184

 
20

 
204

Interest rate swaps

 
320

 

 
320

Total liabilities
$
933

 
$
504

 
$
20

 
$
1,457

___________
(1)
As of June 30, 2012 and December 31, 2011, we had cash equivalents of $574 million and $1,249 million included in cash and cash equivalents and $149 million and $166 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
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 periods indicated (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Balance, beginning of period
$
17

 
$
12

 
$
17

 
$
30

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
Included in net loss:
 
 
 
 
 
 
 
Included in operating revenues(1)
(24
)
 
10

 
(17
)
 
6

Included in fuel and purchased energy expense(2)
2

 
1

 

 

Included in OCI

 
4

 
4

 
5

Purchases, issuances and settlements:
 
 
 
 
 
 
 
Purchases
1

 
1

 
1

 
1

Issuances
(1
)
 

 
(1
)
 

Settlements
(5
)
 
(7
)
 
(11
)
 
(21
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
Transfers into level 3(4)

 

 

 

Transfers out of level 3(5)

 

 
(3
)
 

Balance, end of period
$
(10
)
 
$
21

 
$
(10
)
 
$
21

Change in unrealized gains (losses) relating to instruments still held at end of period
$
(22
)
 
$
11

 
$
(17
)
 
$
7

___________
(1)
For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.

15



(3)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into/out of level 1 during the three and six months ended June 30, 2012 and 2011.
(4)
There were no transfers out of level 2 into level 3 for the three and six months ended June 30, 2012 and 2011.
(5)
We had $3 million of transfers out of level 3 into level 2 for the six months ended June 30, 2012. There were no transfers out of level 3 for the three months ended June 30, 2012 and for the three and six months ended June 30, 2011.
5.
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
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, 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) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. 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 portion of our debt is indexed to base rates, primarily LIBOR. We have historically used 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. As of June 30, 2012, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 11 years.
As of June 30, 2012 and December 31, 2011, 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):
Derivative Instruments
 
Notional Amounts
 
June 30, 2012
 
December 31, 2011
Power (MWh)
 
(21
)
 
(21
)
Natural gas (MMBtu)
 
(68
)
 
(200
)
Interest rate swaps(1)
 
$
1,592

 
$
5,639

____________
(1)
Approximately $4.1 billion at December 31, 2011 was related to hedges of our First Lien Credit Facility's variable rate debt that was converted to fixed rate debt. On March 26, 2012, we terminated the interest rate swaps formerly hedging our First Lien Credit Facility.
Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. 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 any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of June 30, 2012, was $339 million for which we have posted collateral of $244 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, Corporate Revolving Facility and First Lien Term Loans. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $5 million would be required and that no counterparty could request immediate, full settlement.
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. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election will be reflected in earnings and could create more volatility in our earnings. The fair value of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting will be reclassified to earnings in

16



future periods as the related economic transactions affect earnings or if the forecasted transaction becomes probable of not occurring. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge are recorded 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 (or economically hedged) within operating activities or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) 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 hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and swaps), fuel and purchased energy expense (for natural gas contracts and swaps) and interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. 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, swaps and options) and interest expense (for interest rate swaps except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — In January 2011, we repaid approximately $1.2 billion of our First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps hedging the scheduled variable interest payments. With the repayment of these First Lien Credit Facility term loans, unrealized losses of approximately $91 million in AOCI related to the interest rate swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into earnings as an additional loss on interest rate derivatives during the first quarter of 2011. We have presented the reclassification of unrealized losses from AOCI into earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as loss on interest rate derivatives on our Consolidated Condensed Statements of Operations. On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Condensed Statements of Operations for the six months ended June 30, 2012 and approximately $142 million reflected the realization of losses recorded in prior periods.
Derivatives Included on Our Consolidated Condensed Balance Sheet
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
  
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$

 
$
1,049

 
$
1,049

Long-term derivative assets
6

 
152

 
158

Total derivative assets
$
6

 
$
1,201

 
$
1,207

 
 
 
 
 
 
Current derivative liabilities
$
31

 
$
1,212

 
$
1,243

Long-term derivative liabilities
166

 
110

 
276

Total derivative liabilities
$
197

 
$
1,322

 
$
1,519

Net derivative assets (liabilities)
$
(191
)
 
$
(121
)
 
$
(312
)

17



 
December 31, 2011
 
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$

 
$
1,051

 
$
1,051

Long-term derivative assets
10

 
103

 
113

Total derivative assets
$
10

 
$
1,154

 
$
1,164

 
 
 
 
 
 
Current derivative liabilities
$
166

 
$
978

 
$
1,144

Long-term derivative liabilities
154

 
125

 
279

Total derivative liabilities
$
320

 
$
1,103

 
$
1,423

Net derivative assets (liabilities)
$
(310
)
 
$
51

 
$
(259
)

 
June 30, 2012
 
December 31, 2011
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments(1):
 
 
 
 
 
 
 
Interest rate swaps
$
6

 
$
176

 
$
10

 
$
149

Commodity instruments
28

 
4

 
51

 
18

Total derivatives designated as cash flow hedging instruments
$
34

 
$
180

 
$
61

 
$
167

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
21

 
$

 
$
171

Commodity instruments
1,173

 
1,318

 
1,103

 
1,085

Total derivatives not designated as hedging instruments
$
1,173

 
$
1,339

 
$
1,103

 
$
1,256

Total derivatives
$
1,207

 
$
1,519

 
$
1,164

 
$
1,423

____________
(1)
Includes accumulated fair value of derivative instruments as of the date hedge accounting was discontinued, net of amortized fair value for settlement periods which have transpired.
Derivatives Included on Our Consolidated Condensed Statements of Operations
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 and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings.

18



The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized gain (loss)
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
(60
)
 
$
(157
)
 
$
(106
)
Commodity derivative instruments
94

 
42

 
212

 
52

Total realized gain (loss)
$
94

 
$
(18
)
 
$
55

 
$
(54
)
 
 
 
 
 
 
 
 
Unrealized gain (loss)(1)
 
 
 
 
 
 
 
Interest rate swaps
$
3

 
$
24

 
$
149

 
$
(38
)
Commodity derivative instruments
(346
)
 
26

 
(268
)
 
(39
)
Total unrealized gain (loss)
$
(343
)
 
$
50

 
$
(119
)
 
$
(77
)
Total mark-to-market activity, net
$
(249
)
 
$
32

 
$
(64
)
 
$
(131
)
___________
(1)
In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized and unrealized gain (loss)