CALPINE CORP, 10-K filed on 2/10/2012
Annual Report
Document and Entity Information Document (USD $)
12 Months Ended
Dec. 31, 2011
Feb. 7, 2012
Jun. 30, 2011
Document and Entity Information [Abstract]
 
 
 
Entity Registrant Name
CALPINE CORP 
 
 
Entity Central Index Key
0000916457 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2011 
 
 
Document Fiscal Year Focus
2011 
 
 
Document Fiscal Period Focus
FY 
 
 
Amendment Flag
false 
 
 
Entity Common Stock, Shares Outstanding
 
481,338,627 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Public Float
 
 
$ 4,491,000,000 
Consolidated Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Operating revenues
$ 6,800 
$ 6,545 
$ 6,463 
Operating expenses:
 
 
 
Fuel and purchased energy expense
4,349 
3,974 
3,897 
Plant operating expense
904 
868 
868 
Depreciation and amortization expense
550 
570 
456 
Sales, general and other administrative expense
131 
151 
174 
Other operating expense
87 
100 
101 
Total operating expenses
6,021 
5,663 
5,496 
Impairment losses
0 
116 
4 
(Gain) on sale of assets, net
0 
(119)
0 
(Income) loss from unconsolidated investments in power plants
(21)
(16)
(50)
Income from operations
800 
901 
1,013 
Interest expense
760 
813 
815 
Loss on interest rate derivatives
145 
223 
0 
Interest (income)
(9)
(11)
(16)
Debt extinguishment costs
94 
91 
76 
Other (income) expense, net
21 
15 
13 
Income (loss) before income taxes and discontinued operations
(211)
(230)
125 
Income tax expense (benefit)
(22)
(68)1
15 
Income (loss) before discontinued operations
(189)
(162)
110 
Discontinued operations, net of tax expense
0 
193 
35 
Net income (loss)
(189)
31 
145 
Net (income) loss attributable to the noncontrolling interest
(1)
0 
4 
Net income (loss) attributable to Calpine
$ (190)
$ 31 
$ 149 
Basic earnings (loss) per common share attributable to Calpine:
 
 
 
Weighted average shares of common stock outstanding (in thousands)
485,381 
486,044 
485,659 
Income (loss) before discontinued operations attributable to Calpine
$ (0.39)
$ (0.33)
$ 0.24 
Discontinued operations, net of tax expense, attributable to Calpine
$ 0.00 
$ 0.39 
$ 0.07 
Net income (loss) per common share attributable to Calpine — basic
$ (0.39)
$ 0.06 
$ 0.31 
Diluted earnings (loss) per common share attributable to Calpine:
 
 
 
Weighted average shares of common stock outstanding (in thousands)
485,381 
487,294 
486,319 
Income (loss) before discontinued operations attributable to Calpine
$ (0.39)
$ (0.33)
$ 0.24 
Discontinued operations, net of tax expense, attributable to Calpine
$ 0.00 
$ 0.39 
$ 0.07 
Net income (loss) per common share attributable to Calpine — diluted
$ (0.39)
$ 0.06 
$ 0.31 
Consolidated Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Net income (loss)
$ (189)
$ 31 
$ 145 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
(69)
25 
180 
Reclassification adjustment for (gain) loss on cash flow hedges realized in net (income) loss
(25)
141 
(335)
Unrealized actuarial losses arising during period
(3)
0 
0 
Foreign currency translation gain (loss)
(1)
2 
4 
Income tax (expense) benefit
45 
(27)
43 
Other comprehensive income (loss)
(53)
141 
(108)
Comprehensive income (loss)
(242)
172 
37 
Comprehensive (income) loss attributable to the noncontrolling interest
(1)
0 
4 
Comprehensive income (loss) attributable to Calpine
$ (243)
$ 172 
$ 41 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Current assets:
 
 
Cash and cash equivalents ($285 and $345 attributable to VIEs)
$ 1,252 
$ 1,327 
Accounts receivable, net of allowance of $13 and $2
598 
669 
Margin deposits and other prepaid expense
193 
221 
Restricted cash, current ($57 and $177 attributable to VIEs)
139 
195 
Derivative assets, current
1,051 
725 
Inventory and other current assets
329 
292 
Total current assets
3,562 
3,429 
Property, plant and equipment, net ($4,313 and $6,602 attributable to VIEs)
13,019 
12,978 
Restricted cash, net of current portion ($53 and $52 attributable to VIEs)
55 
53 
Investments
80 
80 
Long-term derivative assets
113 
170 
Other assets
542 
546 
Total assets
17,371 
17,256 
Current liabilities:
 
 
Accounts payable
435 
514 
Accrued interest payable
200 
132 
Debt, current portion ($41 and $132 attributable to VIEs)
104 
152 
Derivative liabilities, current
1,144 
718 
Income taxes payable
3 
5 
Other current liabilities
276 
268 
Total current liabilities
2,162 
1,789 
Debt, net of current portion ($2,522 and $4,069 attributable to VIEs)
10,321 
10,104 
Deferred income tax liability, net of current
0 
77 
Long-term derivative liabilities
279 
370 
Other long-term liabilities
245 
247 
Total liabilities
13,007 
12,587 
Commitments and contingencies (see Note 15)
   
   
Stockholders’ equity:
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2011 and 2010
0 
0 
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 490,468,815 shares issued and 481,743,738 shares outstanding at December 31, 2011, and 444,883,356 shares issued and 444,435,198 shares outstanding at December 31, 2010
1 
1 
Treasury stock, at cost, 8,725,077 and 448,158 shares, respectively
(125)
(5)
Additional paid-in capital
12,305 
12,281 
Accumulated deficit
(7,699)
(7,509)
Accumulated other comprehensive loss
(178)
(125)
Total Calpine stockholders’ equity
4,304 
4,643 
Noncontrolling interest
60 
26 
Total stockholders’ equity
4,364 
4,669 
Total liabilities and stockholders’ equity
$ 17,371 
$ 17,256 
Balance Sheet Parenthetical (Parentheticals) (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Cash and cash equivalents attributable to VIE
$ 285 
$ 345 
Accounts Receivable, allowance for doubtful accounts
13 
2 
Restricted cash, current attributable to VIE
57 
177 
Property, plant and equipment, net attributable to VIE
4,313 
6,602 
Restricted cash, net of current portion attributable to VIE
53 
52 
Debt, current portion attributable to VIE
41 
132 
Debt, net of current portion attributable to VIE
$ 2,522 
$ 4,069 
Preferred Stock, par value
$ 0.001 
$ 0.001 
Preferred Stock, authorized shares
100,000,000 
100,000,000 
Preferred Stock, issued shares
0 
0 
Preferred Stock, outstanding shares
0 
0 
Common Stock, par value
$ 0.001 
$ 0.001 
Common Stock, authorized shares
1,400,000,000 
1,400,000,000 
Common Stock, issued shares
490,468,815 
444,883,356 
Common Stock, outstanding shares
481,743,738 
444,435,198 
Treasury Stock, shares
8,725,077 
448,158 
Consolidated Statements of Stockholders’ Equity (USD $)
In Millions
Total
Common Stock [Member]
Treasury Stock [Member]
Additional Paid-in Capital [Member]
Retained Earnings (Accumulated Deficit) [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Noncontrolling Interest [Member]
Balance at Dec. 31, 2008
$ 4,372 
$ 1 
$ (1)
$ 12,217 
$ (7,689)
$ (158)
$ 2 
Treasury stock transactions
(2)
0 
(2)
0 
0 
0 
0 
Stock-based compensation expense
38 
0 
0 
38 
0 
0 
0 
Other
1 
0 
0 
1 
0 
0 
0 
Net income (loss)
145 
0 
0 
0 
149 
0 
(4)
Other comprehensive income (loss)
(108)
0 
0 
0 
0 
(108)
0 
Balance at Dec. 31, 2009
4,446 
1 
(3)
12,256 
(7,540)
(266)
(2)
Treasury stock transactions
(2)
0 
(2)
0 
0 
0 
0 
Stock-based compensation expense
24 
0 
0 
24 
0 
0 
0 
Other
29 
0 
0 
1 
0 
0 
28 
Net income (loss)
31 
0 
0 
0 
31 
0 
0 
Other comprehensive income (loss)
141 
0 
0 
0 
0 
141 
0 
Balance at Dec. 31, 2010
4,669 
1 
(5)
12,281 
(7,509)
(125)
26 
Treasury stock transactions
(120)
0 
(120)
0 
0 
0 
0 
Stock-based compensation expense
24 
0 
0 
24 
0 
0 
0 
Other
33 
0 
0 
0 
0 
0 
33 
Net income (loss)
(189)
0 
0 
0 
(190)
0 
1 
Other comprehensive income (loss)
(53)
0 
0 
0 
0 
(53)
0 
Balance at Dec. 31, 2011
$ 4,364 
$ 1 
$ (125)
$ 12,305 
$ (7,699)
$ (178)
$ 60 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Cash flows from operating activities:
 
 
 
Net income (loss)
$ (189)
$ 31 
$ 145 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
587 1
615 1
556 1
Debt extinguishment costs
82 
91 
37 
Deferred income taxes
(21)
(26)
16 
Impairment losses
0 
116 
4 
(Gain) loss on sale of power plants and other, net
13 
(314)
37 
Unrealized mark-to-market activities, net
(30)2
56 2
(87)2
(Income) loss from unconsolidated investments in power projects
(21)
(16)
(50)
Return on unconsolidated investments in power plants
6 
11 
11 
Stock-based compensation expense
24 
24 
38 
Other
6 
1 
(2)
Change in operating assets and liabilities, net of effects of acquisitions:
 
 
 
Accounts receivable
74 
91 
108 
Derivative instruments, net
15 
(52)
(118)
Other assets
1 
277 
235 
Accounts payable and accrued expenses
28 
(43)
(19)
Settlement of non-hedging interest rate swaps
189 
69 
0 
Other liabilities
11 
(2)
(150)
Net cash provided by operating activities
775 
929 
761 
Cash flows from investing activities:
 
 
 
Purchases of property, plant and equipment
(683)
(369)
(179)
Proceeds from sale of power plants, interests and other
13 
954 
0 
Purchase of Conectiv assets and BRSP, net of cash acquired
0 
(1,680)
0 
Cash acquired due to reconsolidation of OMEC
0 
8 
0 
Capital contributions to unconsolidated investments
0 
0 
(19)
Return of investment from unconsolidated investments
0 
0 
9 
Settlement of non-hedging interest rate swaps
(189)
(69)
0 
(Increase) decrease in restricted cash
54 
322 
(59)
Purchases of deferred transmission credits
(31)
0 
0 
Other
0 
3 
(2)
Net cash used in investing activities
(836)
(831)
(250)
Cash flows from financing activities:
 
 
 
Borrowings under Term Loan and New Term Loan
1,657 
0 
0 
Repayments on NDH Project Debt
(1,283)
0 
0 
Issuance of First Lien Notes
1,200 
3,491 
0 
Repayments on First Lien Credit Facility
(1,195)
(3,477)
(785)
Borrowings from project financing, notes payable and other
327 
1,272 
1,034 
Repayments of project financing, notes payable and other
(550)
(937)
(1,361)
Capital contributions from noncontrolling interest holder
33 
17 
0 
Financing costs
(81)
(136)
(65)
Stock repurchases
(119)
0 
0 
Refund of financing costs
0 
10 
0 
Other
(3)
0 
(2)
Net cash provided by (used in) financing activities
(14)
240 
(1,179)
Net increase (decrease) in cash and cash equivalents
(75)
338 
(668)
Cash and cash equivalents, beginning of period
1,327 
989 
1,657 
Cash and cash equivalents, end of period
1,252 
1,327 
989 
Cash paid during the period for:
 
 
 
Interest, net of amounts capitalized
656 
635 
761 
Income taxes
18 
21 
7 
Supplemental disclosure of non-cash investing and financing activities:
 
 
 
Change in capital expenditures included in accounts payable
(24)
1 
6 
Settlement of commodity contract with project financing
0 
0 
79 
Liabilities assumed in BRSP acquisition
0 
85 
0 
Conversion of Project Debt to Noncontrolling Interest
0 
11 
0 
Issuance of First Lien Notes in exchange for First Lien Credit Facility term loans
0 
0 
1,200 
Amended Steamboat project debt
$ 0 
$ 0 
$ 448 
Organization and Operations
Organization and Operations
Organization and Operations
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 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, including industrial companies, retail power providers, utilities, municipalities, independent electric system operators, 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.
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
Consolidation of OMEC — We were required by U.S. GAAP to adopt new accounting standards for VIEs which became effective January 1, 2010 that 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 U.S. GAAP, we consolidated OMEC effective January 1, 2010. Our Consolidated Financial Statements for the year ended December 31, 2009 present our investment in OMEC’s revenues and expenses under the equity method of accounting. We made no other changes to our group of subsidiaries that we consolidate as a result of the adoption of these new standards. See Note 5 for further discussion of accounting for our VIEs.
Equity Method Investments — We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, and Whitby, a 50% equity interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement. See Note 5 for further discussion of our VIEs and unconsolidated investments.
Revision —  We have revised the amount reported on our Consolidated Statement of Operations as loss on interest rate derivatives by approximately $24 million for the year ended December 31, 2010. The offsetting reduction was to the amount reported as interest expense. This revision had no impact on our financial condition, results of operations or cash flows. See Note 8 for further information about our interest rate swaps formerly hedging our First Lien Credit Facility.
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 Financial Statements. Actual results could differ from those estimates.
Fair Value of Financial Instruments and Derivatives
The carrying values of 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, 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 to be creditworthy 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 counterparties, including our receivable, commodity and derivative transactions. 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 derivative 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.
Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:
•
financial institutions and trading companies;
•
regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and
•
oil, natural gas, chemical and other energy-related industrial companies.
We have concentrations of credit risk with a few of our commercial customers relating to our sales of power, steam and hedging and optimization activities. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties for our commodity and derivative transactions. Currently, certain of our marketing counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements.
We also have unfunded credit exposure to several European financial institutions related to our Russell City Project Debt and Los Esteros Project Debt. These financial institutions continue to provide construction funding in accordance with the terms of the debt agreements. Should one or all of these financial institutions be unable to perform under their obligations, it would not have a material adverse effect on our financial position or results of operations. See Note 6 for a further discussion of our Russell City Project Debt and Los Esteros Project Debt.
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 December 31, 2011 and 2010, we had cash and cash equivalents of $306 million and $269 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 Balance Sheets and Statements of Cash Flows.
The table below represents the components of our restricted cash as of December 31, 2011 and 2010 (in millions):
 
 
2011
 
2010
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
11

 
$
42

 
$
53

 
$
44

 
$
25

 
$
69

Rent reserve
—

 
—

 
—

 
22

 
5

 
27

Construction/major maintenance
33

 
10

 
43

 
35

 
14

 
49

Security/project/insurance
79

 
—

 
79

 
75

 
7

 
82

Other
16

 
3

 
19

 
19

 
2

 
21

Total
$
139

 
$
55

 
$
194

 
$
195

 
$
53

 
$
248

___________
(1)
At both December 31, 2011 and 2010, debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.
Accounts Receivable and Payable
Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance accounts after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.
The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.
Inventory
At December 31, 2011 and 2010, we had inventory of $294 million and $262 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 are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
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 previously subject to first priority liens under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan and certain of our interest rate swap agreements. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our 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 Notes, Corporate Revolving Facility, Term Loan and New Term Loan. See Note 9 for a further discussion on our amounts and use of collateral.
Deferred Financing Costs
Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write off the original deferred financing costs and capitalize the new issuance costs, or continue to amortize the original deferred financing costs and immediately expense the new issuance costs.
Property, Plant and Equipment, Net
Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, repairs or replacements when they appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and accounted for the assets under purchase accounting. All well costs, except well workovers, have been capitalized since our purchase date.
We depreciate our assets under the straight line method over the shorter of their estimated useful life or lease term using an estimated salvage value which approximates 10% of the depreciable cost basis for our power plant assets where we own the land or have a favorable option to purchase the land at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for our rotable equipment. During 2009, we reviewed our accounting policies related to depreciation including our estimates of useful lives. We determined changing from composite depreciation to component depreciation for our rotable natural gas-fired power plant assets, and changing our Geysers Assets depreciation from the units of production method to the straight line method was preferable under U.S. GAAP. We also revised our estimates of useful lives. See Note 4 for further discussion regarding our changes in depreciation, changes in useful lives and the effective date of our changes.
Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and a gain or loss is recorded as plant operating expense.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
During 2011, we did not record any impairment losses. During 2010, we impaired approximately $95 million related to South Point (see Note 3 for further information related to our acquisition of the South Point lease and subsequent impairment of our South Point assets) and development costs of approximately $21 million associated with two development projects that originated prior to our Chapter 11 bankruptcy proceedings. We continued to market these projects after our Effective Date, but during 2010 we determined that their continued development was unlikely. During 2009, we had miscellaneous impairments of approximately $4 million.
Asset Retirement Obligation
We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2011 and 2010, our asset retirement obligation liabilities were $27 million and $51 million, respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return. Our asset retirement obligation liabilities for the year ended December 31, 2011 decreased by $24 million primarily related to a revision in the expected settlement dates of the asset retirement obligations on several of our power plants.
Revenue Recognition
Our operating revenues are composed of the following:
•
power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation including capacity payments received from PJM capacity auctions, variable payments for power and steam, which are related to generation, host steam and RECs from our Geysers Assets, and other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues;
•
realized and unrealized revenues from derivative instruments as a result of our marketing, hedging and optimization activities; and
•
other service revenues.
Power and Steam
Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. Such contracts often meet the criteria of a derivative but are generally eligible for and designated under the normal purchase normal sale exemption. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.
With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the variable payment as revenue but do not record any fuel and purchased energy expense.
Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
Leases — Contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract.
The total contractual future minimum lease receipts for these contracts are as follows (in millions):

2012
$
300

2013
287

2014
286

2015
288

2016
291

Thereafter
1,210

Total
$
2,662

 
 
Accounting for Derivative Instruments
We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. 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 are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. See Note 8 for a further discussion on our accounting for derivatives.
Fuel and Purchased Energy Expense
Fuel and purchased energy expense is composed of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, and the cost of power and natural gas purchased from third parties for marketing, hedging and optimization activities as well as realized and unrealized mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas contracts including financial gas transactions economically hedging anticipated future power sales that do not qualify for hedge accounting treatment.
Plant Operating Expense
Plant operating expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance, insurance and property taxes. We recognize these expenses when the service is performed or in the period in which the expense relates.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. See Note 10 for a further discussion on our income taxes.
Earnings (Loss) per Share
Basic earnings (loss) per share is calculated using the weighted average shares outstanding during the period and includes restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted earnings (loss) per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method. See Note 11 for a further discussion of our earnings (loss) per share.
Stock-Based Compensation
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model to estimate the fair value of our employee stock options on the grant date. The Black-Scholes option-pricing model and the Monte Carlo simulation model take into account certain variables, which are further explained in Note 12.
New Accounting Standards and Disclosure Requirements
Fair Value Measurement — In May 2011, 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 is not expected to impact any of our fair value measurements but will 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;
•
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 do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.
Comprehensive Income — In June 2011, FASB issued Accounting Standards Update 2011-05, “Comprehensive Income” to amend requirements relating to the presentation of comprehensive income. The update eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity and provides an entity with the option to present comprehensive income in a single continuous financial statement or in two separate but consecutive statements. The new requirements relating to the presentation of comprehensive income are retrospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. Also, in December 2011, FASB issued Accounting Standards Update 2011-12, “Comprehensive Income” to abrogate the requirement for presentation in the income statement of the effect on net income of reclassification adjustments out of AOCI as required in Accounting Standards Update 2011-05. We adopted all of the presentation requirements related to these updates for the year ended December 31, 2011.
Disclosures about Offsetting Assets and Liabilities — In December 2011, 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.
Acquisitions, Divestitures and Discontinued Operations
Acquisitions, Divestitures and Discontinued Operations
Acquisitions, Divestitures and Discontinued Operations
Conectiv Acquisition
On July 1, 2010, we, through our indirect, wholly owned subsidiary NDH, completed the Conectiv Acquisition. The assets acquired include 18 operating power plants and the York Energy Center that was under construction and achieved COD on March 2, 2011, totaling 4,491 MW of capacity. We did not acquire Conectiv's trading book, load serving auction obligations or collateral requirements. Additionally, we did not assume any of Conectiv's off-site environmental liabilities, environmental remediation liabilities in excess of $10 million related to assets located in New Jersey that are subject to ISRA, or pre-close accumulated pension and retirement welfare liabilities; however, we did assume pension liabilities on future services and compensation increases for past services for approximately 130 grandfathered union employees who joined Calpine as a result of the Conectiv Acquisition. During the second half of 2010, we initiated a voluntary retirement incentive program which reduced the number of employees covered by our pension obligation by 31 employees. The net proceeds of $1.3 billion received from the NDH Project Debt were used, together with available operating cash, to pay the Conectiv Acquisition purchase price of approximately $1.64 billion and also fund a cash contribution from Calpine Corporation to NDH of $110 million to fund completion of the York Energy Center.
The Conectiv Acquisition provided us with a significant presence in the Mid-Atlantic market, one of the most robust competitive power markets in the U.S., and positioned us with three scale markets instead of two (California and Texas) giving us greater geographic diversity. We accounted for the Conectiv Acquisition under the acquisition method of accounting in accordance with U.S. GAAP.
During the second quarter of 2011, we finalized the valuations of the net assets acquired in the Conectiv Acquisition which is summarized in the following table (in millions). We did not record any material valuation adjustments during the first half of 2011, and we did not recognize any goodwill as a result of this acquisition.

Consideration
$
1,640

 
 
Final values of identifiable assets acquired and liabilities assumed:
 
Assets:
 
Current assets
$
78

Property, plant and equipment, net
1,574

Other long-term assets
85

Total assets acquired
1,737

Liabilities:
 
Current liabilities
46

Long-term liabilities
51

Total liabilities assumed
97

Net assets acquired
$
1,640


Acquisition of Broad River and South Point Leases
On December 8, 2010, we, through our wholly owned, indirect subsidiary, Calpine BRSP, purchased entities from CIT Capital USA Inc. that held the leases for our Broad River and South Point power plants by assuming debt with a fair value of approximately $297 million and a cash payment of approximately $40 million. Prior to this purchase, our Broad River power plant was operated under a sale-leaseback transaction that was accounted for as a failed sale-leaseback financing transaction and our South Point power plant was accounted for as an operating lease. The purchase of the entities holding the power plant leases only added an incremental $85 million in consolidated debt, as the transaction eliminated approximately $212 million recorded as debt and accrued interest owed to CIT Capital USA Inc. under our Broad River power plant lease.
We recorded a total pre-tax loss of approximately $125 million on our Consolidated Statement of Operations for the year ended December 31, 2010 for this transaction, which was recorded as shown below (in millions):
 
Broad River: debt extinguishment costs
$
30

South Point: impairment loss
95

Total loss recorded for this transaction
$
125


Broad River — Prior to the purchase, we operated the Broad River power plant under a lease that was accounted for as a failed sale-leaseback financing transaction under U.S. GAAP. The lease liability was included in project financing, notes payable and other debt balance and the power plant assets were included in our property plant and equipment. As a result of the purchase, we did not adjust the historical value of the assets. We allocated the value of the consideration paid in the transaction based upon the fair value of both plants, and the result was an allocation of assumed debt that was greater than the prior debt obligation resulting in a pre-tax loss of approximately $30 million. Because we primarily exchanged future lease obligations for a debt obligation, the resulting loss is recorded as debt extinguishment costs for accounting purposes.
South Point — Prior to the purchase, we accounted for the South Point lease as an operating lease. We allocated the consideration paid in the transaction based upon the fair value of both plants. The result was an allocation of consideration paid for South Point that was in excess of the fair value of assets acquired by approximately $95 million, which was primarily due to the elimination of a lease levelization asset associated with the prior lease, which was no longer proper on a consolidated basis. The resulting loss has been reported as an impairment loss for accounting purposes.
While the transaction resulted in a one-time, pre-tax loss, in the longer-term, the acquisition of these entities grants us greater flexibility and more control of the future operation of both plants and simplified a previously complex leasing arrangement.
Sale of Blue Spruce and Rocky Mountain
On December 6, 2010, we, through our indirect, wholly owned subsidiaries Riverside Energy Center, LLC and CDHI, completed the sale of 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, and we recorded a pre-tax gain of approximately $209 million during the fourth quarter of 2010. The results of operations for Blue Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Statement of Operations for years ended December 31, 2010 and 2009.
Discontinued Operations
The table below presents the components of our discontinued operations for the periods presented (in millions):
 
 
2010
 
2009
Operating revenues
 
$
92

 
$
101

Gain on disposal of discontinued operations
 
209

 
—

Income from discontinued operations before taxes
 
43

 
35

Less: Income tax expense
 
59

 
—

Discontinued operations, net of tax
 
$
193

 
$
35


Other Asset Sales
On December 8, 2010, we sold a 25% undivided interest in the assets of our Freestone power plant for approximately $215 million in cash. We recorded a pre-tax gain of approximately $119 million in December 2010, which is included in (gain) on sale of assets, net on our Consolidated Statement of Operations. We continue to operate Freestone after the sale.
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
As of December 31, 2011 and 2010, the components of property, plant and equipment, are stated at cost less accumulated depreciation as follows (in millions):
 
2011
 
2010
Buildings, machinery and equipment
$
15,074

 
$
14,669

Geothermal properties
1,163

 
1,102

Other
156

 
182

 
16,393

 
15,953

Less: Accumulated depreciation
4,158

 
3,690

 
12,235

 
12,263

Land
91

 
93

Construction in progress
693

 
622

Property, plant and equipment, net
$
13,019

 
$
12,978


Total depreciation expense, including amortization of leased assets, recorded in income from operations and discontinued operations for the years ended December 31, 2011, 2010 and 2009, was $560 million, $568 million and $469 million, respectively.
We have various debt instruments that are collateralized by certain of our property, plant and equipment. See Note 6 for a detailed discussion of such instruments.
Change in Depreciation Methods, Useful Lives and Salvage Values
During 2009, we reviewed our accounting policies related to depreciation including our estimates of useful lives and salvage values. As further 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.
Component Depreciation for Rotable Parts at our Natural Gas-Fired Power Plants — Effective October 1, 2009, we componentized our rotable parts for our natural gas-fired power plant assets for purposes of calculating depreciation. Prior to October 1, 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. The 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. The 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 — Effective October 1, 2009, we began calculating our depreciation for our Geysers Assets under the straight line method. Prior to October 1, 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. The change in depreciation methods was made because steam flow decline rates have become very small over the past several years as a result of our water injection program where, on average, we reinject approximately 18 million gallons of reclaimed wastewater a day back into the reservoir to replenish natural steam withdrawn for the production of power. The expectation is that the steam reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future and expected future generation is now only limited by the physical useful life of the Geysers Assets. 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 revised our estimates of the remaining composite useful lives of our Geysers Assets effective October 1, 2009 to 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.
The changes described above resulted in an increase in our historical depreciation expense of approximately $28 million related to our natural gas-fired power plants and a decrease in historical depreciation expense of approximately $3 million for our Geysers Assets for a net decrease to our net income attributable to Calpine of approximately $25 million or approximately $(0.05) to our basic and diluted earnings per share for the year ended December 31, 2009.
Buildings, Machinery and Equipment
This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under capital leases. See Note 6 for further information regarding these assets under capital leases.
Other
This component primarily includes software and emission reduction credits that are power plant specific and not available to be sold.
Capitalized Interest
The total amount of interest capitalized was $24 million, $15 million and $8 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. We have the following types of VIEs consolidated in our financial statements:
Subsidiaries with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. 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. See Note 6 for further information regarding our project debt and Note 2 for information regarding our restricted cash balances.
Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our ownership and thus constitute a VIE.
VIEs with a Purchase Option — Riverside Energy Center and OMEC have agreements that provide third parties a fixed price option to purchase power plant assets exercisable in the years 2012 and 2019, respectively, with an aggregate capacity of 1,211 MW. These purchase options limit the risk and reward of our ownership and, thus, constitute a VIE.
Consolidation of VIEs
We consolidate our VIEs where we determine that we have 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. We have determined 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 determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes 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, and 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 is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
•
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
•
evaluate if an entity is a VIE and whether we are the primary beneficiary whenever 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 or when there are other changes in the powers held by individual variable interest holders.
On August 23, 2011, we closed on the $373 million Los Esteros Project Debt to fund the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle power plant to a 308 MW combined-cycle generation power plant. The addition of this project debt resulted in Los Esteros Critical Energy Facility, LLC meeting the definition of a VIE for which we have determinded we are the primary beneficiary. There were no other changes to our determination of whether we are the primary beneficiary of our VIEs for the year ended December 31, 2011.
Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also 25% owned by a third party. We fully consolidate this entity in our Consolidated Financial Statements and account for the third party ownership interest as a noncontrolling interest.
VIE Disclosures
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can only be used 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 met the separate disclosure criteria, we determined 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 there are agreements that prohibit the debt holders of the VIE from recourse to the general credit of Calpine Corporation or its other subsidiaries. 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 the VIE from providing guarantees on the debt of others and where the amounts were material to our financial statements.
The VIEs meeting the above disclosure criteria are majority owned subsidiaries of Calpine Corporation and include natural gas-fired power plants with an aggregate capacity of approximately 11,391 MW, including 584 MW under construction, and 13,656 MW, including 1,029 MW under construction, at December 31, 2011 and 2010, 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 $171 million for the year ended December 31, 2011. During the year ended December 31, 2010, Calpine Corporation provided $540 million to NDH, an indirect, wholly owned subsidiary, to fund the Conectiv Acquisition, including $110 million to complete the construction of the York Energy Center. Additionally, Calpine Corporation provided support to our other VIEs in the form of cash and other contributions other than amounts contractually required of $46 million during the year ended December 31, 2010.
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 Balance Sheets. During 2009, we were not the primary beneficiary of OMEC based upon the accounting guidance in 2009, and did not consolidate OMEC. As required by U.S. GAAP, we consolidated OMEC effective January 1, 2010. At December 31, 2011 and 2010, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of December 31, 2011
 
2011
 
2010
Greenfield LP
50%
 
72

 
77

Whitby
50%
 
8

 
3

Total investments
 
 
$
80

 
$
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 Balance Sheets. At December 31, 2011 and 2010, equity method investee debt was approximately $462 million and $494 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $231 million and $247 million at December 31, 2011 and 2010, respectively.
Our equity interest in the net income from OMEC for the year ended December 31, 2009, and both Greenfield LP and Whitby for the years ended December 31, 2011, 2010 and 2009 are recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the years indicated (in millions):
 
(Income) from Unconsolidated
Investments in Power Plants
 
Distributions
 
2011
 
2010
 
2009
 
2011
 
2010
 
2009
OMEC(1)
$
—

 
$
—

 
$
(32
)
 
$
—

 
$
—

 
$
9

Greenfield LP
(12
)
 
(8
)
 
(16
)
 
2

 
6

 
9

Whitby
(9
)
 
(8
)
 
(2
)
 
4

 
5

 
2

Total
$
(21
)
 
$
(16
)
 
$
(50
)
 
$
6

 
$
11

 
$
20

___________
(1)
OMEC was consolidated effective January 1, 2010. See Note 2.
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%.
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.
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 7 and 14 after the start of commercial operation. GE 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 plant, and we do not consolidate it due to, but not limited to, the fact that GE directs the most significant activities of the power plant including operations and maintenance.
Significant Subsidiary — OMEC met the criteria of a significant unconsolidated subsidiary for the year ended December 31, 2009. OMEC was consolidated effective January 1, 2010. The condensed combined financial statements for our unconsolidated subsidiaries for the period in which OMEC was a significant unconsolidated subsidiary and was accounted for under the equity method of accounting is presented below (in millions):
Condensed Combined Statement of Operations
of Our Unconsolidated Subsidiaries
For the Year Ended December 31, 2009
 
 
2009
Revenues
$
256

Operating expenses
195

Income from operations
61

Interest (income) expense
2

Other (income) expense, net
5

Net income
$
54



Debt
Debt
Debt
Our debt at December 31, 2011 and 2010, was as follows (in millions):
 
2011
 
2010
First Lien Notes(1)
$
5,892

 
$
4,691

Project financing, notes payable and other(2)(3)
1,691

 
1,922

Term Loan and New Term Loan(2)(4)
1,646

 
—

CCFC Notes
972

 
965

Capital lease obligations
224

 
236

NDH Project Debt(4)
—

 
1,258

First Lien Credit Facility(1)
—

 
1,184

Total debt
10,425

 
10,256

Less: Current maturities
104

 
152

Debt, net of current portion
$
10,321

 
$
10,104

_____________
(1)
On January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed below.
(2)
On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described below.
(3)
On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City and on August 23, 2011, we closed on the $373 million Los Esteros Project Debt to fund the upgrade of our Los Esteros Critical Energy Facility, both further described below.
(4)
On March 9, 2011, we borrowed $1.3 billion under the Term Loan and repaid and terminated the NDH Project Debt as discussed below.
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2011, are as follows (in millions):
 
2012
$
104

2013
135

2014
392

2015
164

2016
1,177

Thereafter
8,496

Total debt
10,468

Less: Discount
43

Total
$
10,425


Our First Lien Notes and Termination of the First Lien Credit Facility
Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2011
 
2010
 
2011
 
2010
2017 First Lien Notes
$
1,200

 
$
1,200

 
7.5
%
 
7.5
%
2019 First Lien Notes
400

 
400

 
8.2

 
8.2

2020 First Lien Notes
1,092

 
1,091

 
8.1

 
8.1

2021 First Lien Notes
2,000

 
2,000

 
7.7

 
7.7

2023 First Lien Notes(2)
1,200

 
—

 
8.0

 
—

Total First Lien Notes
$
5,892

 
$
4,691

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
(2)
On January 14, 2011, we issued $1.2 billion in aggregate principal amount of 7.875% senior secured notes due 2023 in a private placement. Interest on the 2023 First Lien Notes is payable semi-annually on January 15 and July 15 of each year, beginning on July 15, 2011. The 2023 First Lien Notes will mature on January 15, 2023.
Following our emergence from Chapter 11, our First Lien Credit Facility served as our primary debt facility. Beginning in late 2009, we began to repay or exchange our First Lien Credit Facility term loans through proceeds received from the issuances of the First Lien Notes, together with operating cash. On January 14, 2011, we repaid the remaining approximately $1.2 billion from the proceeds from the issuance of the 2023 First Lien Notes, together with operating cash, thereby terminating the First Lien Credit Facility in accordance with its terms.
Our First Lien Notes are secured equally and ratably with indebtedness incurred under our Corporate Revolving Facility, Term Loan and New Term Loan (described below), 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. Repayment of the NDH Project Debt also eliminated the restrictions against our NDH subsidiaries being guarantors to our First Lien Notes and Corporate Revolving Facility. On March 9, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add our NDH subsidiaries as guarantors to our Corporate Revolving Facility and Term Loan. On April 26, 2011, we executed supplemental indentures for the First Lien Notes to add the NDH subsidiaries as guarantors. On June 17, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors of our Corporate Revolving Facility, Term Loan and New Term Loan. On July 22, 2011, we executed supplemental indentures for the First Lien Notes to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors.
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.
In connection with the issuance of the 2023 First Lien Notes, we recorded approximately $22 million of deferred financing costs on our Consolidated Balance Sheet during 2011, and we recorded approximately $19 million in debt extinguishment costs during the year ended December 31, 2011, related to the repayment and termination of the First Lien Credit Facility.
The Term Loan and the New Term Loan and Repayment of the NDH Project Debt and Other Project Debt
On March 9, 2011, we entered into and borrowed $1.3 billion under the Term Loan. We used the net proceeds received, together with operating cash on hand to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. The NDH Project Debt was originally established to partially fund the Conectiv Acquisition.
The Term Loan provides for a senior secured term loan facility in an aggregate principal amount of $1.3 billion and bears 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 Term Loan credit agreement), 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 Term Loan will be payable at the end of each quarter commencing on June 30, 2011, 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 Term Loan 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 Term Loan, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent. We may also reprice the interest rate on the Term Loan, subject to approval from the Lenders and subject to a 1% premium if a repricing transaction occurs prior to the first anniversary of the closing date. We may elect to extend the maturity of any term loans under the Term Loan, in whole or in part subject to approval from those lenders holding such term loans. The Term Loan is 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 Term Loan outstanding within thirty (30) days after the date of such change of control triggering event.
In connection with the Term Loan, 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 Term Loan is 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 Term Loan 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 Term Loan amounts (as defined in the Credit Agreement) may declare all the Term Loan amounts outstanding to be due and payable immediately.
In connection with the Term Loan, we recorded deferred financing costs of approximately $14 million on our Consolidated Balance Sheet during 2011, and we recorded approximately $74 million in debt extinguishment costs during the year ended December 31, 2011, which includes approximately $36 million from the write-off of unamortized deferred financing costs, the write-off of approximately $25 million of debt discount and approximately $13 million in prepayment premiums related to the NDH Project Debt.
On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan. The New Term Loan carries substantially the same terms as the Term Loan and matures on April 1, 2018. The New Term Loan also contains very similar covenants, qualifications, exceptions and limitations as the Term Loan and First Lien Notes.
In connection with the New Term Loan, we recorded deferred financing costs of approximately $5 million on our Consolidated Balance Sheet during 2011, and we recorded approximately $5 million in debt extinguishment costs during the year ended December 31, 2011.
Project Financing, Notes Payable and Other
The components of our project financing, notes payable and other are (in millions, except for interest rates):
 
Outstanding at
December 31,
 
Weighted Average
Effective Interest Rates(1)
 
 
2011
 
2010
 
2011
 
2010
 
Steamboat due 2017
$
437

 
$
445

 
6.6
%
 
6.6
%
 
OMEC due 2019
355

 
364

 
6.8

 
6.8

 
Russell City
244

 
—

 
4.1

 
—

 
Calpine BRSP due 2014
232

 
297

 
5.7

 
5.7

 
Pasadena(2)
185

 
208

 
8.8

 
8.6

 
Bethpage Energy Center 3, LLC due 2020-2025(3)
98

 
103

 
7.0

 
7.0


Los Esteros
83

 
—

 
3.8

 
—

 
Gilroy note payable due 2014
49

 
64

 
10.6

 
10.6

 
Metcalf(4)
—

 
251

 
—

 
6.9

 
Deer Park(4)
—

 
99

 
—

 
7.7

 
Gilroy Energy Center, LLC
—

 
38

 
—

 
7.3

 
Whitby Holdings(5)
—

 
26

 
—

 
9.1

 
GEC Holdings, LLC preferred interest
—

 
14

 
—

 
16.6

 
Other
8

 
13

 
—

 
—

 
Total
$
1,691

 
$
1,922

 
 
 
 
 
_____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
(2)
Represents a sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
(3)
Represents a weighted average of first and second lien loans for the weighted average effective interest rates.
(4)
On June 17, 2011, we repaid Metcalf and Deer Park project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described above.
(5)
The Whitby Holdings debt was purchased from a third party in 2011.
Our project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders' recourse under these project financings is limited to such collateral.
Russell City — 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, a 619 MW natural gas-fired, combined-cycle power plant under construction located in Hayward, California, which 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 December 31, 2011, approximately $244 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%.
In connection with the closing of the Russell City Project Debt, we recorded deferred financing costs of approximately $27 million on our Consolidated Balance Sheet during 2011.
Los Esteros — 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 308 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 December 31, 2011, approximately $83 million had been drawn under the construction loan and approximately $30 million of letters of credit were issued under the letter of credit facilities.
In connection with the closing of the Los Esteros Project Debt, we recorded deferred financing costs of approximately $12 million on our Consolidated Balance Sheet during the year ended December 31, 2011.
CCFC Notes
On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately $1.0 billion aggregate principal amount of 8.0% CCFC Notes in a private placement. The net proceeds received, together with CCFC cash on hand, were used to repay the CCFC Term Loans and CCFC Old Notes with the remaining cash distributed to CCFC's indirect parent, CCFCP, which was used by CCFCP to redeem its CCFCP Preferred Shares. In connection with the CCFC Refinancing, we recorded deferred financing costs of approximately $21 million on our Consolidated Balance Sheet during the year ended December 31, 2009, and we recorded $49 million in debt extinguishment costs during the year ended December 31, 2009.
The CCFC Notes and the related guarantees are secured, subject to certain exceptions and permitted liens, by all real and personal property of CCFC and CCFC’s material subsidiaries (including the CCFC Guarantors), consisting primarily of six natural gas power plants as well as the equity interests in CCFC and the CCFC Guarantors. The CCFC Notes are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any of our other non-CCFC or CCFC Finance subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with CES and has various service agreements in place with other subsidiaries of Calpine Corporation. The CCFC Notes mature on June 1, 2016 and the weighted average interest rates, which includes the amortization of deferred financing costs and debt discount, was 8.9% for both 2011 and 2010.
Capital Lease Obligations
The following is a schedule by year of future minimum lease payments under capital leases and failed sale-leaseback transactions together with the present value of the net minimum lease payments as of December 31, 2011 (in millions):
 
Sale-Leaseback Transactions(1)
 
Capital Lease
 
Total
2012
$
41

 
$
40

 
$
81

2013
38

 
38

 
76

2014
26

 
39

 
65

2015
25

 
37

 
62

2016
25

 
40

 
65

Thereafter
143

 
200

 
343

Total minimum lease payments
298

 
394

 
692

Less: Amount representing interest
110

 
170

 
280

Present value of net minimum lease payments
$
188

 
$
224

 
$
412

____________
(1)
Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
The primary types of property leased by us are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The remaining lease terms range up to 37 years (including lease renewal options). Some of the lease agreements contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project financing agreements. At both December 31, 2011 and 2010, the asset balances for the leased assets totaled approximately $1.0 billion with accumulated amortization of $340 million and $312 million, respectively. See Note 15 for discussion of capital leases guaranteed by Calpine Corporation.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities as of December 31, 2011 and 2010 (in millions):
 
2011
 
2010
Corporate Revolving Facility(1)
$
440

 
$
443

CDHI(2)
193

 
165

NDH Project Debt credit facility(3)
—

 
34

Various project financing facilities
130

 
69

Total
$
763

 
$
711

__________
(1)
When we entered into our $1.0 billion Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced with letters of credit issued under our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during 2011.
(2)
On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.
(3)
We repaid and terminated the NDH Project Debt on March 9, 2011.
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 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 will 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 which matures on December 11, 2012, under which up to $200 million is available for letters of credit. On January 10, 2012, we amended the CDHI letter of credit facility to increase the facility to $300 million and extend 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. We measured the fair value of our debt instruments as of December 31, 2011 and 2010, 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 December 31, 2011 and 2010 (in millions):
 
2011
 
2010
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
6,219

 
$
5,892

 
$
4,695

 
$
4,691

Project financing, notes payable and other(1)
1,467

 
1,504

 
1,673

 
1,708

Term Loan and New Term Loan
1,615

 
1,646

 
—

 
—

CCFC Notes
1,070

 
972

 
1,067

 
965

NDH Project Debt
—

 
—

 
1,303

 
1,258

First Lien Credit Facility
—

 
—

 
1,182

 
1,184

Total
$
10,371

 
$
10,014

 
$
9,920

 
$
9,806

____________
(1)
Excludes leases that are accounted for as failed sale-leaseback transactions under U.S. GAAP and included in our project financing, notes payable and other balance.

Assets and Liabilities with Recurring Fair Value Measurements
Assets and Liabilities with Recurring Fair Value Measurements
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 in restricted cash on our Consolidated 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 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 can also be 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 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 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 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.
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010, 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 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 futures 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 futures contracts
899

 
—

 
—

 
899

Commodity forward contracts(2)
—

 
184

 
20

 
204

Interest rate swaps
—

 
320

 
—

 
320

Total liabilities
$
933

 
$
504

 
$
20

 
$
1,457

 
 
 
 
 
 
 
 
 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2010
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,297

 
$
—

 
$
—

 
$
1,297

Margin deposits
162

 
—

 
—

 
162

Commodity instruments:
 
 
 
 
 
 
 
Commodity futures contracts
550

 
—

 
—

 
550

Commodity forward contracts(2)
—

 
287

 
54

 
341

Interest rate swaps
—

 
4

 
—

 
4

Total assets
$
2,009

 
$
291

 
$
54

 
$
2,354

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
6

 
$
—

 
$
—

 
$
6

Commodity instruments:
 
 
 
 
 
 
 
Commodity futures contracts
574

 
—

 
—

 
574

Commodity forward contracts(2)
—

 
119

 
24

 
143

Interest rate swaps
—

 
371

 
—

 
371

Total liabilities
$
580

 
$
490

 
$
24

 
$
1,094

___________
(1)
As of December 31, 2011 and 2010, we had cash equivalents of $1,249 million and $1,094 million included in cash and cash equivalents and $166 million and $203 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 years ended December 31, 2011, 2010 and 2009 (in millions):
 
2011
 
2010
 
2009
Balance, beginning of period
$
30

 
$
38

 
$
105

Realized and unrealized gains (losses):
 
 
 
 
 
Included in net income:
 
 
 
 
 
Included in operating revenues(1)
5

 
7

 
14

Included in fuel and purchased energy expense(2)
—

 
—

 
5

Included in OCI
2

 
2

 
(4
)
Purchases, issuances and settlements:
 
 
 
 
 
Settlements
(18
)
 
(20
)
 
(48
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
Transfers into level 3(4)
(2
)
 
—

 
—

Transfers out of level 3(5)
—

 
3

 
(34
)
Balance, end of period
$
17

 
$
30

 
$
38

Change in unrealized gains relating to instruments still held at end of period(2)
$
5

 
$
7

 
$
19

___________
(1)
For power contracts and Heat Rate swaps and options, included on our Consolidated Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Statements of Operations.
(3)
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 1 during the years ended December 31, 2011, 2010 and 2009.
(4)
We had $2 million in losses transferred out of level 2 into level 3 for the year ended December 31, 2011, due to changes in market liquidity in various power and natural gas markets.There were no significant transfers into level 3 for the years ended December 31, 2010 and 2009.
(5)
There were no significant transfers out of level 3 for the year ended 2011. We had $3 million in losses and $(34) million in (gains) transferred out of level 3 into level 2 for the years ended December 31, 2010 and 2009, respectively, due to changes in market liquidity in various power markets.

Derivative Instruments
Derivative Instruments
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 December 31, 2011, the maximum length of our PPAs extend approximately 23 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative cash flow hedging instruments was 1 and 12 years, respectively.
As of December 31, 2011 and 2010, 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
 
2011
 
2010
Power (MWh)
 
(21
)
 
(50
)
Natural gas (MMBtu)
 
(200
)
 
31

Interest rate swaps(1)
 
$
5,639

 
$
6,171

____________
(1)
Approximately $4.1 billion and $3.3 billion at December 31, 2011 and 2010, respectively, related to variable rate debt that was converted to fixed rate debt in 2011 and 2010.
Certain of our derivative instruments contain credit-contingent provisions that require us to maintain a minimum credit rating 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 any additional collateral posted as a result of a one credit downgrade would be material. The aggregate fair value of our derivative liabilities with credit-contingent provisions as of December 31, 2011, was $138 million for which we have posted collateral of $90 million by posting margin deposits or granted additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan. However, if our credit rating were downgraded, we estimate that additional collateral of $2 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 Statements of Operations until the period of delivery. 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 or interest rate swap breakage costs associated with interest rate swaps formerly hedging project debt) on our Consolidated 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 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. Upon repayment of our NDH Project Debt and other project debt, we terminated and settled the interest rate swaps related to these debt instruments and recorded $17 million to loss on interest rate derivatives during 2011. See Note 6 for further information about the repayment of the NDH Project Debt as well as the repayment of other project debt with proceeds from our New Term Loan.
Derivatives Not Designated as Hedging Instruments — Along with our portfolio of transactions which are accounted for as hedges under U.S. GAAP, 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 and Other Project Debt — During 2010, we repaid approximately $3.5 billion of our First Lien Credit Facility term loans, which had approximately $3.3 billion notional amount of interest rate swaps hedging the scheduled variable interest payments, and in January 2011, we repaid the remaining approximately $1.2 billion of 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 the remaining First Lien Credit Facility term loans, the remaining 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 income as an additional loss on interest rate derivatives during 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to loss on interest rate derivatives during 2011 resulting from the repayment of project debt in 2011. During 2010, we reclassified approximately $206 million out of AOCI and into income as additional loss on interest rate derivatives related to interest rate swaps formerly hedging our First Lien Credit Facility term loans. We have presented the reclassification of unrealized losses from AOCI into income 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 Statements of Operations. We also have determined that, based upon current market conditions and consistent with our Risk Management Policy, liquidation of these interest rate swaps is not economically beneficial and additional future losses are limited. Accordingly, we have elected to retain and hold these interest rate swap positions at this time. The interest rate swaps formerly hedging our First Lien Credit Facility term loans substantially mature in 2012.
Derivatives Included on Our Consolidated Balance Sheet
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2011 and 2010 (in millions):
 
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
)

 
December 31, 2010
 
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
—

 
$
725

 
$
725

Long-term derivative assets
4

 
166

 
170

Total derivative assets
$
4

 
$
891

 
$
895

 
 
 
 
 
 
Current derivative liabilities
$
197

 
$
521

 
$
718

Long-term derivative liabilities
174

 
196

 
370

Total derivative liabilities
$
371

 
$
717

 
$
1,088

Net derivative assets (liabilities)
$
(367
)
 
$
174

 
$
(193
)

 
 
December 31, 2011
 
December 31, 2010
 
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:
 
 
 
 
 
 
 
Interest rate swaps
$
10

 
$
149

 
$
2

 
$
143

Commodity instruments
51

 
18

 
161

 
52

Total derivatives designated as cash flow hedging instruments
$
61

 
$
167

 
$
163

 
$
195

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$
—

 
$
171

 
$
2

 
$
228

Commodity instruments
1,103

 
1,085

 
730

 
665

Total derivatives not designated as hedging instruments
$
1,103

 
$
1,256

 
$
732

 
$
893

Total derivatives
$
1,164

 
$
1,423

 
$
895

 
$
1,088


Derivatives Included on Our Consolidated 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 Statements of Operations as a component of mark-to-market activity within our net income.
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 not designated as hedging instruments and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009 (in millions):
 
 
2011
 
2010
 
2009
Realized gain (loss)
 
 
 
 
 
Interest rate swaps
$
(193
)
 
$
(31
)
 
$
(32
)
Commodity derivative instruments
143

 
114

 
37

Total realized gain (loss)
$
(50
)
 
$
83

 
$
5

 
 
 
 
 
 
Unrealized gain (loss)(1)
 
 
 
 
 
Interest rate swaps
$
55

 
$
(199
)
 
$
8

Commodity derivative instruments
(25
)
 
143

 
79

Total unrealized gain (loss)
$
30

 
$
(56
)
 
$
87

Total mark-to-market activity, net
$
(20
)
 
$
27

 
$
92


___________
(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.
 
2011
 
2010
 
2009
Realized and unrealized gain (loss)
 
 
 
 
 
Power contracts included in operating revenues
$
(20
)
 
$
(19
)
 
$
7

Natural gas contracts included in fuel and purchased energy expense
138

 
276

 
109

Interest rate swaps included in interest expense
7

 
(7
)
 
(24
)
Loss on interest rate derivatives
(145
)
 
(223
)
 
—

Total mark-to-market activity, net
$
(20
)
 
$
27

 
$
92


Derivatives Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the years ended December 31, 2011 and 2010 (in millions):
 
 
Gains (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(2)
 
Gain (Loss) Reclassified from
AOCI into Income  (Ineffective
Portion)
 
2011
 
2010
 
2011
 
2010
 
2011
 
2010
Interest rate swaps
$
(23
)
 
$
193

 
$
(138
)
(3) 
$
(389
)
(4) 
$
(1
)
 
$
—

Commodity derivative instruments
(71
)
 
(27
)
 
163

(1) 
248

(1) 
(2
)
 
—

Total
$
(94
)
 
$
166

 
$
25

 
$
(141
)
  
$
(3
)
 
$
—

____________
(1)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Statement of Operations.
(2)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $172 million and $122 million at December 31, 2011 and 2010, respectively. Our other components of AOCI were not material at December 31, 2011 and 2010.
(3)
Reclassification of losses from OCI to earnings consisted of $32 million in losses from the reclassification of interest rate contracts due to settlement, $15 million in losses from terminated interest rate contracts due to the repayment of project debt in 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans.
(4)
Reclassification of losses from OCI to earnings consisted of $183 million in losses from the reclassification of interest rate contracts due to settlement and $206 million in losses from interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans.
Assuming constant December 31, 2011 power and natural gas prices and interest rates, we estimate that pre-tax net gains of $15 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 into earnings (positive or negative) will be for the next 12 months.

Use of Collateral
Use of Collateral
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 various debt agreements as collateral under certain of our power and natural gas agreements 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 share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.
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 December 31, 2011 and 2010 (in millions):
 
2011
 
2010
Margin deposits(1)
$
140

 
$
162

Natural gas and power prepayments
42

 
43

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
182

 
$
205

 
 
 
 
Letters of credit issued(3)
$
581

 
$
588

First priority liens under power and natural gas agreements(4)
1

 
—

First priority liens under interest rate swap agreements
318

 
391

Total letters of credit and first priority liens with our counterparties
$
900

 
$
979

 
 
 
 
Margin deposits held by us posted by our counterparties(1)(5)
$
34

 
$
6

Letters of credit posted with us by our counterparties
—

 
66

Total margin deposits and letters of credit posted with us by our counterparties
$
34

 
$
72

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation.
(2)
At December 31, 2011 and 2010, $162 million and $183 million, respectively, were included in margin deposits and other prepaid expense and $20 million and $22 million were included in other assets at December 31, 2011 and 2010, respectively, on our Consolidated Balance Sheets.
(3)
When we entered into our Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued under the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit issued under our Corporate Revolving Facility used for our commodity procurement and risk management activities as of December 31, 2010 include those that were back-stopped of approximately $63 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011.
(4)
At December 31, 2010, the fair value of our commodity derivative instruments collateralized by first priority liens was an asset of $193 million; therefore, there was no collateral exposure at December 31, 2010.
(5)
Included in other current liabilities on our Consolidated 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.
Income Taxes
Income Taxes
Income Taxes
Income Tax Expense (Benefit)
The jurisdictional components of income (loss) from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2011, 2010 and 2009, are as follows (in millions):
 
2011
 
2010
 
2009
U.S.
$
(232
)
 
$
(226
)
 
$
116

International
20

 
(4
)
 
13

Total
$
(212
)
 
$
(230
)
 
$
129


The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2011, 2010 and 2009, consisted of the following (in millions):
 
2011
 
2010
 
2009
Current:
 
 
 
 
 
Federal
$
(16
)
 
$
(1
)
 
$
(2
)
State
12

 
10

 
(2
)
Foreign
3

 
3

 
3

Total current
(1
)
 
12

 
(1
)
Deferred:
 
 
 
 
 
Federal
(33
)
 
(70
)
 
13

State
9

 
—

 
4

Foreign
3

 
(10
)
 
(1
)
Total deferred
(21
)
 
(80
)
 
16

Total income tax expense (benefit)
$
(22
)
 
$
(68
)
(1) 
$
15

_________
(1)
Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI.
For the years ended December 31, 2011, 2010 and 2009, our income tax rates did not bear a customary relationship to statutory income tax rates, primarily as a result of the impact of our valuation allowance, state income taxes and changes in unrecognized tax benefits. A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2011, 2010 and 2009, is as follows:
 
2011
 
2010
 
2009
Federal statutory tax expense (benefit) rate
(35.0
)%
 
(35.0
)%
 
35.0
 %
State tax expense (benefit), net of federal benefit
6.5

 
2.8

 
1.0

Depletion in excess of basis
—

 
(1.3
)
 
—

Valuation allowances against future tax benefits
56.7

 
33.6

 
(139.2
)
Valuation allowances related to reconsolidation of CCFC
(36.0
)
 
—

 
—

Foreign taxes
(0.9
)
 
9.9

 
(9.2
)
Non-deductible reorganization items
0.5

 
0.3

 
1.3

Income from cancellation of indebtedness
—

 
—

 
69.0

Intraperiod allocation
19.9

 
(40.1
)
 
45.4

Bankruptcy settlement
(15.7
)
 
—

 
—

Change in unrecognized tax benefits
(6.6
)
 
0.6

 
1.4

Permanent differences and other items
0.2

 
(0.4
)
 
6.9

Effective income tax expense (benefit) rate
(10.4
)%
 
(29.6
)%
 
11.6
 %

Deferred Tax Assets and Liabilities
The components of the deferred income taxes as of December 31, 2011 and 2010, are as follows (in millions):
 
2011
 
2010
Deferred tax assets:
 
 
 
NOL and credit carryforwards
$
3,290

 
$
3,138

Taxes related to risk management activities and derivatives
58

 
18

Reorganization items and impairments
318

 
422

Foreign capital losses
24

 
25

Other differences
26

 
12

Deferred tax assets before valuation allowance
3,716

 
3,615

Valuation allowance
(2,336
)
 
(2,386
)
Total deferred tax assets
1,380

 
1,229

Deferred tax liabilities: property, plant and equipment
(1,364
)
 
(1,280
)
Net deferred tax asset (liability)
16

 
(51
)
Less: Current portion deferred tax asset (liability)
(2
)
 
(4
)
Less: Non-current deferred tax asset
18

 
30

Deferred income tax liability, non-current
$
—

 
$
(77
)

Consolidation of CCFC and Calpine Tax Reporting Groups — For federal income tax reporting purposes, our historical tax reporting group was comprised primarily of two separate groups, CCFC and its subsidiaries, which we referred to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we referred to as the Calpine group. During the first quarter of 2011, we elected to consolidate our CCFC and Calpine groups for federal income tax reporting purposes and Calpine will file a consolidated federal income tax return for the year ended December 31, 2011 that will include the CCFC group. As a result of the consolidation, the CCFC group deferred tax liabilities will be eligible to offset existing Calpine group NOLs that were reserved by a valuation allowance. Accordingly, we recorded a one-time federal deferred income tax benefit of approximately $76 million during the first quarter of 2011 to reduce our valuation allowance. For the years ended December 31, 2010 and 2009, the CCFC group was deconsolidated from the Calpine group for federal income tax reporting purposes.
Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) and income from discontinued operations with a partial offsetting amount recognized in OCI and discontinued operations. The following table details the effects of our intraperiod tax allocations for the year ended December 31, 2011, 2010 and 2009 (in millions).
 
2011
 
2010
 
2009
Intraperiod tax allocation expense (benefit) included in continuing operations
$
42

 
$
(86
)
 
$
43

Intraperiod tax allocation expense (benefit) included in discountinued operations
$
—

 
$
59

 
$
—

Intraperiod tax allocation expense (benefit) included in OCI
$
(45
)
 
$
27

 
$
(43
)
NOL Carryforwards — Our NOL carryforwards consist primarily of federal NOL carryforwards of approximately $7.9 billion, which expire between 2023 and 2031, and NOL carryforwards in 33 states and the District of Columbia totaling approximately $4.2 billion, which expire between 2012 and 2032, substantially all of which are offset with a full valuation allowance. We also have approximately $1.0 billion in foreign NOLs, substantially all of which are offset with a full valuation allowance. The NOL carryforwards available are subject to limitations on their annual usage. Under federal and applicable state income tax laws, a corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior years subject to certain time limitations as prescribed by the taxing authorities. 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 IRC. 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. At December 31, 2011, approximately $2.4 billion of our $7.9 billion federal NOLs are not subject to annual Section 382 limitations. When considering our cumulative annual Section 382 limitations, in addition to our post-Effective Date NOLs that are not limited, our total unrestricted NOLs are approximately $6.3 billion. If a subsequent ownership change were to occur as a result of future transactions in our common 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.
Under state income tax laws, 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 IRC. During 2011, we analyzed the effect of our change in ownership on the Effective Date for each of our significant states to determine the amount of our NOL limitation. The analysis determined that $640 million of our state NOLs are expected to expire unutilized as a result of statutory limitations on the use of some of our pre-emergence state NOLs as of the Effective Date or the cessation of business operations in various tax jurisdictions. We reduced our deferred tax asset for state NOLs that we are unable to utilize and made an equal reduction in our valuation allowance. The result did not have an impact on our income tax expense in 2011. In 2012 we will continue with our analysis and adjust our state NOLs where appropriate.
To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation requires our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock 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 IRC. We believe as of the filing of this Report, neither circumstance was met. 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 was 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.
Should our Board of Directors elect to impose these restrictions, it will 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.
We had certain intercompany accounts payable/receivable balances that were eliminated as part of the final steps of our emergence from bankruptcy. There was no effect to our federal NOLs, however, there was a reduction in our state NOLs of $44 million which was partially offset by a reduction in current state taxable income of $24 million. The resulting net reduction to our state NOLs was offset by an equal reduction in our valuation allowance. The reduction did not have an impact on our income tax expense in 2011.
As a result of the settlement with holders of the CalGen Third Lien Debt and the final distribution to the holders of allowed unsecured claims in accordance with our Plan of Reorganization in 2011, we recognized approximately $66 million and $39 million for federal and state income tax purposes, respectively, in cancellation of debt income related to this distribution for federal income tax reporting.
Income Tax Audits — We remain subject to various audits and reviews by 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 2007 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.
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 2005 through 2008. CRA concluded that there were no adjustments on two of the entities but further review was required on the remaining two entities. We have timely provided all supporting documentation and any additional documents requested by the CRA on the remaining two entities, and we believe that the CRA will conclude their audit within the first six months of 2012. Although no formal assessment has been received, based on recent communications, we believe that the CRA may be planning a reassessment; however, we are not currently aware of the nature or amount of the adjustments, if any, and accordingly we have not established a tax reserve. If a reassessment should occur, any adjustment to taxable income would first be offset against any existing NOLs that are available. At this time, we are unable to determine the likelihood whether the outcome would have a material adverse effect on our financial position, results of operations or cash flow.
Valuation Allowance — U.S. 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. Due to our history of losses, we were unable to assume future profits; however, since our emergence from Chapter 11, we are able to consider available tax planning strategies.
As of December 31, 2011, we have provided a valuation allowance of approximately $2.3 billion on certain federal, state and foreign tax jurisdiction deferred tax assets to reduce the amount of these assets to the extent necessary to result in an amount that is more likely than not to be realized. The net change in our valuation allowance was a decrease of $50 million, $186 million and $113 million for the years ended December 31, 2011, 2010 and 2009, respectively; all primarily related to changes in our estimates of our ability to utilize our NOL carryforwards.
Unrecognized Tax Benefits
At December 31, 2011, we had unrecognized tax benefits of $74 million. If recognized, $28 million of our unrecognized tax benefits could impact the annual effective tax rate and $46 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 $20 million for income tax matters at December 31, 2011. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit). A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2011, 2010 and 2009, is as follows (in millions):
 
2011
 
2010
 
2009
Balance, beginning of period
$
(88
)
 
$
(98
)
 
$
(90
)
Increases related to prior year tax positions
—

 
(1
)
 
(11
)
Decreases related to prior year tax positions
1

 
11

 
2

Settlements
—

 
—

 
1

Decrease related to lapse of statute of limitations
13

 
—

 
—

Balance, end of period
$
(74
)
 
$
(88
)
 
$
(98
)
Earnings (Loss) per Share
Earnings (Loss) per Share
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, were unresolved. In June 2011, we settled the largest remaining claim outstanding and began the process of distributing the balance of the reserved shares, which was completed during the third quarter of 2011, pursuant to our Plan of Reorganization. Accordingly, although the reserved shares were not issued and outstanding for the balance of the periods presented, 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.
As we incurred a net loss for the year ended December 31, 2011, diluted loss per share for this 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.
Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the years ended December 31, 2011, 2010 and 2009, are as follows (shares in thousands):
 
2011
 
2010
 
2009
Diluted weighted average shares calculation:
 
 
 
 
 
Weighted average shares outstanding (basic)
485,381

 
486,044

 
485,659

Share-based awards
—

 
1,250

 
660

Weighted average shares outstanding (diluted)
485,381

 
487,294

 
486,319


We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2011, 2010 and 2009 because they were anti-dilutive (shares in thousands):
 
2011
 
2010
 
2009
Share-based awards
15,260

 
14,883

 
13,158



Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union 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. 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 between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At December 31, 2011, there were 567,000 and 27,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively.
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term 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.
Stock-based compensation expense recognized was $24 million, $24 million and $38 million for the years ended December 31, 2011, 2010 and 2009, respectively. We did not record any significant 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 years ended December 31, 2011, 2010 and 2009. At December 31, 2011, there was unrecognized compensation cost of $12 million related to options, $16 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 1.3 years for options, 1.3 years for restricted stock and 0.4 years for restricted stock units. We issue new shares from our share 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 year ended December 31, 2011, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2010
17,164,890

 
$
17.44

 
5.6

 
$
8

Granted
953,467

 
$
14.27

 
 
 
 
Exercised
7,554

 
$
11.66

 
 
 
 
Forfeited
197,316

 
$
13.04

 
 
 
 
Expired
247,585

 
$
17.56

 
 
 
 
Outstanding — December 31, 2011
17,665,902

 
$
17.32

 
4.8

 
$
26

Exercisable — December 31, 2011
8,297,284

 
$
19.49

 
4.6

 
$
2

Vested and expected to vest – December 31, 2011
17,377,738

 
$
17.39

 
4.7

 
$
25


The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the years ended December 31, 2011 and 2010. There were no employee stock options exercised during the year ended December 31, 2009.
The fair value of options granted during the years ended December 31, 2011, 2010 and 2009, was determined on the grant date using the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate. Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
2011
 
2010
 
2009
 
Expected term (in years)(1)
6.5

 
4.0 – 6.5

 
6.0 – 6.5

 
Risk-free interest rate(2)
1.7 – 3.2

%
1.3 – 3.3

%
2.3 – 2.9

%
Expected volatility(3)
31.2 – 44.9

%
31.4   – 37.6

%
52.1 – 73.0

%
Dividend yield(4)
—

 
—

 
—

 
Weighted average grant-date fair value (per option)
$
5.49

 
$
1.98

 
$
5.67

 
___________
(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 stock options.
(4)
We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future.
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 year ended December 31, 2011, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2010
2,683,117

2,046,599

$
11.16

Granted
1,636,026

1,475,992

$
14.37

Forfeited
322,034

400,141

$
12.32

Vested
486,751

439,333

$
14.41

Nonvested — December 31, 2011
3,510,358

 
$
12.10


The total fair value of our restricted stock that vested during the years ended December 31, 2011, 2010 and 2009, was approximately $7 million, $4 million and $8 million, respectively.

Defined Contribution and Defined Benefit Plans
Defined Contribution and Defined Benefit Plans
Defined Contribution and Defined Benefit Plans
We maintain two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501(a) of the IRC. Our non-union plan generally covers employees who are not covered by a collective bargaining agreement, and our union plan covers employees who are covered by a collective bargaining agreement. We recorded expenses for these plans of approximately $10 million, $9 million and $9 million for the years ended December 31, 2011, 2010 and 2009, respectively. Employer matching contributions are 100% of the first 5% of compensation a participant defers for the non-union plan. The employee deferral limit is 75% of compensation under both plans.
As part of the Conectiv Acquisition, we assumed approximately $6 million of pension liability for approximately 130 grandfathered union employees who joined Calpine as a result of the Conectiv Acquisition and enrolled them into the New Development Holdings, LLC Union Retirement Plan, a defined benefit plan. PHI retained the pension liability associated with past service cost; however we are responsible for benefits for services after July 1, 2010 and future compensation increases related to past service. During the second half of 2010, we initiated a voluntary retirement incentive program which reduced our pension obligation by 31 employees. Under the New Development Holdings, LLC Union Retirement Plan, retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. As of December 31, 2011 and 2010, our pension assets, liabilities and related costs were not material to us. As of December 31, 2011 and 2010, there were approximately $10 million and $8 million in plan assets and approximately $18 million and $15 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2011 and 2010, was approximately $8 million and $7 million, respectively. For the years ended December 31, 2011 and 2010, we recognized net periodic benefit costs of approximately $1 million and $9 million, respectively. Net pension benefit costs for 2010 includes a one-time charge to pension expense for a voluntary retirement incentive program of approximately $8 million. The voluntary retirement incentive program was accepted by 31 of the 48 eligible employees that were retained as part of the Conectiv Acquisition allowing these employees the ability to commence receiving retirement benefits early without reducing their overall pension benefits. Our net periodic benefit cost is included in plant operating expense on our Consolidated Statements of Operations. As of December 31, 2011 and 2010, the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $3 million and nil, respectively.
In making our estimates of our pension obligation and related costs, we utilize discount rates, rates of compensation increases and rates of return on our assets that we believe are reasonable. Due to relatively small size of our pension liability (which is not considered material), significant changes in these assumptions would not have a material effect on our pension liability. During 2011 and 2010, we made contributions of approximately $3 million and $8 million, respectively, and estimated contributions to the pension plan are expected to be approximately $2 million in 2012. Estimated future benefit payments to participants in each of the next five years are expected to be less than $1 million in each year.

Capital Structure
Capital Structure
Capital Structure
Common Stock
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, were unresolved. In June 2011, we settled the largest remaining claim outstanding and began the process of distributing the balance of the reserved shares, which was completed during the third quarter of 2011, pursuant to our Plan of Reorganization.
Our authorized common stock consists of 1.4 billion shares of Calpine Corporation common stock. Common stock issued as of December 31, 2011 and 2010, was 490,468,815 shares and 444,883,356 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2011 and 2010, was 481,743,738 shares and 444,435,198 shares, respectively. The table below summarizes our common stock activity for the years ended December 31, 2011, 2010 and 2009.
 
Shares
Issued
 
Shares
Held in
Treasury
 
Shares
Held in
Reserve
 
Inter-
Creditor
Disputes
 
Total
Balance, December 31, 2008
429,025,057

 
(65,032
)
 
48,162,203

 
9,752,261

 
486,874,489

Resolution of claims/inter-creditor disputes
13,167,420

 
—

 
(3,415,159
)
 
(9,752,261
)
 
—

Shares issued under Calpine Equity Incentive Plans
1,133,350

 
(262,540
)
 
—

 
—

 
870,810

Balance, December 31, 2009
443,325,827

 
(327,572
)
 
44,747,044

 
—

 
487,745,299

Resolution of claims
488,612

 
—

 
(488,612
)
 
—

 
—

Shares issued under Calpine Equity Incentive Plans
1,068,917

 
(120,586
)
 
—

 
—

 
948,331

Balance, December 31, 2010
444,883,356

 
(448,158
)
 
44,258,432

 
—

 
488,693,630

Resolution of claims
44,258,432

 
—

 
(44,258,432
)
 
—

 
—

Shares issued under Calpine Equity Incentive Plans
1,327,027

 
(139,846
)
 
—

 
—

 
1,187,181

Share repurchase program
—

 
(8,137,073
)
 
—

 
—

 
(8,137,073
)
Balance, December 31, 2011
490,468,815

 
(8,725,077
)
 
—

 
—

 
481,743,738


Treasury Stock
As of December 31, 2011 and 2010, we had treasury stock of 8,725,077 shares and 448,158 shares, respectively, with a cost of $125 million and $5 million, respectively. On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. The announced share repurchase program did not specify an expiration date. The repurchases may be commenced or suspended from time to time without prior notice. Through the filing of this Report, a total of 8,524,576 shares of our outstanding common stock have been repurchased under this program for approximately $124 million at an average price paid of $14.60 per share. Our treasury stock also consists of our common stock withheld to satisfy federal, state and local income tax withholding requirements for vested employee restricted stock awards.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
Long-Term Service Agreements
As of December 31, 2011, the total estimated commitments for LTSAs associated with turbines installed or in storage were approximately $70 million. These commitments are payable over the terms of the respective agreements, which range from 1 to 7 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution and are subject to an annual inflationary adjustment. Certain of these agreements have terms that allow us to cancel the contracts for a fee. If we cancel such contracts, the estimated commitments remaining for LTSAs would be reduced.
Power Plant, Land and Other Operating Leases
We have entered into certain long-term operating leases for power plants, extending through 2020, including renewal options. Some of the lease agreements provide for renewal options at fair value, and some of the agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance agreements. Payments on our operating leases, which may contain escalation clauses or step rent provisions, are recognized on a straight-line basis. Certain capital improvements associated with leased power plants may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. We have also entered into various land and other operating leases for ground facilities and operations, which extend through 2069. Future minimum lease payments under these leases are as follows (in millions):
 
Initial
Year
 
2012
 
2013
 
2014
 
2015
 
2016
 
Thereafter
 
Total
Land and other operating leases
various
 
$
12

 
$
11

 
$
11

 
$
14

 
$
14

 
$
431

 
$
493

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
7

 
$
3

 
$
—

 
$
—

 
$
—

 
$
17

KIAC
2000
 
24

 
24

 
24

 
23

 
22

 
74

 
191

Total power plant leases
 
 
$
31

 
$
31

 
$
27

 
$
23

 
$
22

 
$
74

 
$
208

Total leases
 
 
$
43

 
$
42

 
$
38

 
$
37

 
$
36

 
$
505

 
$
701


During the years ended December 31, 2011, 2010 and 2009, rent expense for power plant and land and other operating leases amounted to $53 million, $60 million and $60 million, respectively.
Production Royalties and Leases
We are obligated under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on consumer price index changes and are not material. Under the terms of most geothermal leases, the royalties accrue as a percentage of power revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level.
Production royalties for geothermal power plants for the years ended December 31, 2011, 2010 and 2009, were $22 million, $25 million and $22 million, respectively.
Office and Equipment Leases
We lease our corporate and regional offices, as well as some of our office equipment, under noncancellable operating leases extending through 2020. Future minimum lease payments under these leases are as follows (in millions):
2012
$
13

2013
12

2014
10

2015
10

2016
9

Thereafter
32

Total
$
86


Lease payments are subject to adjustments for our pro rata portion of annual increases or decreases in building operating costs. During the years ended December 31, 2011, 2010 and 2009, rent expense for noncancellable operating leases was $13 million, $12 million and $12 million, respectively.
Natural Gas Purchases
We enter into natural gas purchase contracts of various terms with third parties to supply natural gas to our natural gas-fired power plants. The majority of our purchases are made in the spot market or under index-priced contracts. At December 31, 2011, we had future commitments of approximately $4.6 billion for natural gas purchases under contracts with terms from 1 to 15 years, and one contract with a term of 30 years.
Guarantees and Indemnifications
As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of our fleet of power plants. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.
At December 31, 2011, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in millions):
Guarantee Commitments
 
2012
 
2013
 
2014
 
2015
 
2016
 
Thereafter
 
Total
Guarantee of subsidiary debt(1)
 
$
76

 
$
73

 
$
272

 
$
36

 
$
36

 
$
236

 
$
729

Standby letters of credit(2)(4)
 
669

 
45

 
—

 
—

 
—

 
49

 
763

Surety bonds(3)(4)(5)
 
—

 
—

 
—

 
—

 
—

 
4

 
4

 Guarantee of subsidiary operating lease payments(4)
 
7

 
7

 
3

 
—

 
—

 
—

 
17

Total
 
$
752

 
$
125

 
$
275

 
$
36

 
$
36

 
$
289

 
$
1,513

____________
(1)
Represents Calpine Corporation guarantees of certain project debt, power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.
(2)
The standby letters of credit disclosed above represent those disclosed in Note 6.
(3)
The majority of surety bonds do not have expiration or cancellation dates.
(4)
These are contingent off balance sheet obligations.
(5)
As of December 31, 2011, $4 million of cash collateral is outstanding related to these bonds.
We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of our subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of our partially owned subsidiaries up to our ownership percentage. The letters of credit issued under various credit facilities support CES risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to ten days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included on our Consolidated Balance Sheets.
Commercial Agreements — In connection with the purchase and sale of power, natural gas and emission allowances to and from third parties with respect to the operation of our power plants, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. These guarantees may include future payment obligations as well as operational performance guarantees and effectively guarantee our future performance under certain agreements.
Purchase and Sale Agreements — In connection with our purchase and sale agreements, we have frequently provided for indemnification by each of the purchaser and the seller, and/or their respective parent, to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.
Other — Additionally, we and our subsidiaries from time to time assume other guarantee and indemnification obligations in conjunction with other transactions such as parts supply agreements, construction agreements and equipment lease agreements. These guarantee and indemnification obligations may include future payment obligations and effectively guarantee our future performance under certain agreements.
Our potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Our total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim will be resolved. As of December 31, 2011, there are no outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations.
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect to our financial position, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect to our financial position, results of operations or cash flows. Further, following the Effective Date, pending actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date, as well as pending litigation against the U.S. Debtors related to such liabilities, generally have been permanently enjoined. Any unresolved claims will continue to be subject to the claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain pending litigation related to pre-petition liabilities may proceed in courts, other than the U.S. Bankruptcy Court, to the extent the parties to such litigation have obtained relief from the permanent injunction.
Pit River Tribe, et al. v. Bureau of Land Management, et al. — On June 17, 2002, the Pit River Tribe filed suit against the BLM and other federal agencies in the U.S. District Court for the Eastern District of California seeking to enjoin further exploration, construction and development of the Calpine Four-Mile Hill Project in the Glass Mountain and Medicine Lake geothermal areas. The complaint challenged the validity of the decisions of the BLM and the U.S. Forest Service to permit the development of the proposed project under two geothermal mineral leases (the Fourmile Hill leases) previously issued by the BLM. The lawsuit also sought to invalidate the leases. Only declaratory and equitable relief was sought.
On November 5, 2006, the U.S. Court of Appeals for the Ninth Circuit issued a decision granting the plaintiffs relief by holding that the BLM had not complied with the National Environmental Policy Act, and other procedural requirements and, therefore, held that the lease extensions were invalid. On August 2, 2010, the Ninth Circuit issued a decision upholding the validity of the leases and confirming the court's order to remand the lease extension decisions for further evaluation, including preparation of an environmental impact statement. On November 4, 2010, the United States District Court for the Eastern District of California entered an order remanding the matter to federal agencies to implement the Court's order. We consider this litigation closed and anticipate it will take the federal agencies several years to implement the Court's order to conduct additional analysis. Accordingly, we plan to remove this matter from future filings until, and if and when, future action is taken by the Pit River Tribe.
In addition, in May 2004, the Pit River Tribe and other interested parties filed two separate suits in the District Court seeking to enjoin exploration, construction, and development of the Telephone Flat leases and proposed project at Glass Mountain. These two cases have remained mostly inactive. However, with the favorable resolution of the litigation over validity of the two Fourmile Hill leases, we anticipate the Pit River Tribe and other interested parties may seek to reactivate the two additional suits, and we are in communication with the U.S. Department of Justice regarding how to proceed.
Environmental Matters
We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the normal operation of our power plants. We do not, however, have environmental violations or other matters that would have a material impact on our financial condition, results of operations or cash flows or that would significantly change our operations. A summary of our larger environmental matters are as follows:
Environmental Remediation of Certain Assets Acquired from Conectiv — As part of the Conectiv Acquisition on July 1, 2010, we assumed environmental remediation liabilities related to certain of the assets located in New Jersey that are subject to the ISRA. We have accrued or paid $10 million related to these liabilities at December 31, 2011. Pursuant to the Conectiv Purchase Agreement, PHI is responsible for any amounts that exceed $10 million associated with New Jersey environmental remediation liabilities. Our accrual is included in our allocation of the Conectiv Acquisition purchase price. See Note 3 for disclosures related to our Conectiv Acquisition.
Other Contingencies
Distribution of Calpine Common Stock under our Plan of Reorganization — On June 2, 2011, we reached a settlement with holders of the CalGen Third Lien Debt which was funded from the sale of a portion of the shares held in reserve. The U.S. Bankruptcy Court approved the settlement with the CalGen Third Lien Debt claimants on June 16, 2011 and the settlement agreements were fully implemented in August 2011. As of December 31, 2011, all 485 million shares authorized in the confirmed Plan of Reorganization have been distributed to creditors in accordance with the terms of the Plan of Reorganization. The distribution of the remaining shares did not represent the issuance of new or additional shares and had no impact on our financial position, results of operations or cash flows. During the fourth quarter of 2011, the U.S. Bankruptcy Court issued an order dismissing the Chapter 11 cases that remained open against the U.S. Debtors; thus, all matters related to our voluntary petitions for relief under Chapter 11 of the Bankruptcy Code filed in 2005 and 2006 are resolved and closed.
Segment and Significant Customer Information
Segment and Significant Customer Information
Segment and Significant Customer Information
We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At December 31, 2011, our reportable segments were West (including geothermal), Texas, North (including Canada and the assets purchased in the Conectiv Acquisition) and Southeast. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.
Commodity Margin includes our power and steam revenues, sales of purchased power and physical 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 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 Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).
 
Year Ended December 31, 2011
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
2,372

 
$
2,306

 
$
1,336

 
$
786

 
$
—

 
$
6,800

Intersegment revenues
12

 
23

 
7

 
135

 
(177
)
 
—

Total operating revenues
$
2,384

 
$
2,329

 
$
1,343

 
$
921

 
$
(177
)
 
$
6,800

Commodity Margin
$
1,061

 
$
469

 
$
704

 
$
240

 
$
—

 
$
2,474

Add: Mark-to-market commodity activity, net and other(1)(2)
113

 
(102
)
 
(13
)
 
1

 
(32
)
 
(33
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
380

 
235

 
177

 
141

 
(29
)
 
904

Depreciation and amortization expense
192

 
135

 
138

 
90

 
(5
)
 
550

Sales, general and other administrative expense
43

 
43

 
24

 
22

 
(1
)
 
131

Other operating expenses(3)
41

 
3

 
30

 
5

 
(2
)
 
77

(Income) from unconsolidated investments in power plants
—

 
—

 
(21
)
 
—

 
—

 
(21
)
Income (loss) from operations
518

 
(49
)
 
343

 
(17
)
 
5

 
800

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
751

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
145

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
115

Loss before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
(211
)

 
Year Ended December 31, 2010
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
2,525

 
$
2,162

 
$
978

 
$
880

 
$
—

 
$
6,545

Intersegment revenues
12

 
22

 
6

 
138

 
(178
)
 
—

Total operating revenues
$
2,537

 
$
2,184

 
$
984

 
$
1,018

 
$
(178
)
 
$
6,545

Commodity Margin
$
1,080

 
$
504

 
$
535

 
$
272

 
$
—

 
$
2,391

Add: Mark-to-market commodity activity, net and other(1)
69

 
89

 
21

 
22

 
(30
)
 
171

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
351

 
285

 
138

 
123

 
(29
)
 
868

Depreciation and amortization expense
207

 
150

 
111

 
109

 
(7
)
 
570

Sales, general and other administrative expense
55

 
38

 
45

 
12

 
1

 
151

Other operating expenses(3)
59

 
2

 
28

 
4

 
(2
)
 
91

Impairment losses
97

 
—

 
—

 
19

 
—

 
116

(Gain) on sale of assets, net
—

 
(119
)
 
—

 
—

 
—

 
(119
)
(Income) from unconsolidated investments in power plants
—

 
—

 
(16
)
 
—

 
—

 
(16
)
Income from operations
380

 
237

 
250

 
27

 
7

 
901

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
802

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
223

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
106

Loss before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
(230
)

 
Year Ended December 31, 2009
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
3,311

 
$
1,816

 
$
558

 
$
778

 
$
—

 
$
6,463

Intersegment revenues
28

 
63

 
16

 
97

 
(204
)
 
—

Total operating revenues
$
3,339

 
$
1,879

 
$
574

 
$
875

 
$
(204
)
 
$
6,463

Commodity Margin
$
1,245

 
$
644

 
$
268

 
$
304

 
$
—

 
$
2,461

Add: Mark-to-market commodity activity, net and other(1)
143

 
(40
)
 
46

 
(5
)
 
(44
)
 
100

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
408

 
232

 
91

 
134

 
3

 
868

Depreciation and amortization expense
188

 
129

 
67

 
80

 
(8
)
 
456

Sales, general and other administrative expense
66

 
63

 
18

 
27

 
—

 
174

Other operating expenses(3)
73

 
14

 
30

 
11

 
(32
)
 
96

Impairment losses
4

 
—

 
—

 
—

 
—

 
4

(Income) from unconsolidated investments in power plants
(32
)
 
—

 
(18
)
 
—

 
—

 
(50
)
Income from operations
681

 
166

 
126

 
47

 
(7
)
 
1,013

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
799

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
89

Income before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
125

__________
(1)
Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009, as well as a non-cash gain from amortization of prepaid power sales agreements for the year ended December 31, 2009.
(2)
Includes $12 million of lease levelization and $8 million of contract amortization for the year ended December 31, 2011 related to contracts that became effective in 2011.
(3)
Excludes $10 million, $9 million and $5 million of RGGI compliance and other environmental costs for the years ended December 31, 2011, 2010 and 2009, respectively, which are components of Commodity Margin.
Significant Customer
For the year ended December 31, 2011, we had one significant customer, PJM Settlement, Inc., that accounted for more than 10% of our annual consolidated revenues. Our revenues of $742 million from PJM Settlement, Inc. for the year ended December 31, 2011, were attributed to our North segment. Our receivables from PJM Settlement, Inc. were $28 million as of December 31, 2011. We did not have a customer that accounted for more than 10% of our annual consolidated revenues for the years ended December 31, 2010 or 2009.
Quarterly Consolidated Financial Data (unaudited)
Quarterly Consolidated Financial Data (unaudited)
Quarterly Consolidated Financial Data (unaudited)
Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, our restructuring activities (including asset sales), the completion of development projects, the timing and amount of curtailment of operations under the terms of certain PPAs, the degree of risk management and marketing, hedging and optimization activities, energy commodity market prices and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of our PPAs are received during the months of May through October.
 
Quarter Ended
 
December 31
 
September 30
 
June 30
 
March 31
 
(in millions, except per share amounts)
2011
 
 
 
 
 
 
 
Operating revenues
$
1,459

 
$
2,209

 
$
1,633

 
$
1,499

Income from operations
196

 
403

 
183

 
18

Income (loss) before discontinued operations attributable to Calpine
$
(13
)
 
$
190

 
$
(70
)
 
$
(297
)
Discontinued operations, net of tax expense, attributable to Calpine
—

 
—

 
—

 
—

Net income (loss) attributable to Calpine
$
(13
)
 
$
190

 
$
(70
)
 
$
(297
)
Basic earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Discontinued operations, net of tax expense, attributable to Calpine
—

 
—

 
—

 
—

Net income (loss) attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Discontinued operations, net of tax expense, attributable to Calpine
—

 
—

 
—

 
—

Net income (loss) attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
2010
 
 
 
 
 
 
 
Operating revenues
$
1,471

 
$
2,130

 
$
1,430

 
$
1,514

Income from operations
89

 
554

 
108

 
150

Income (loss) before discontinued operations attributable to Calpine
$
(186
)
 
$
198

 
$
(119
)
 
$
(55
)
Discontinued operations, net of tax expense, attributable to Calpine
162

 
19

 
4

 
8

Net income (loss) attributable to Calpine
$
(24
)
 
$
217

 
$
(115
)
 
$
(47
)
Basic earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.38
)
 
$
0.41

 
$
(0.25
)
 
$
(0.11
)
Discontinued operations, net of tax expense, attributable to Calpine
0.33

 
0.04

 
0.01

 
0.01

Net income (loss) attributable to Calpine
$
(0.05
)
 
$
0.45

 
$
(0.24
)
 
$
(0.10
)
Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.38
)
 
$
0.41

 
$
(0.25
)
 
$
(0.11
)
Discontinued operations, net of tax expense, attributable to Calpine
0.33

 
0.04

 
0.01

 
0.01

Net income (loss) attributable to Calpine
$
(0.05
)
 
$
0.45

 
$
(0.24
)
 
$
(0.10
)


Schedule of Valuation and Qualifying Accounts Disclosure
Schedule of Valuation and Qualifying Accounts Disclosure
CALPINE CORPORATION AND SUBSIDIARIES
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

Description
Balance at
Beginning
of Year
 
Charged to
Expense
 
Charged to Other Accounts
 
Deductions(1)
 
Balance at
End of Year
 
(in millions)
Year ended December 31, 2011
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
2

 
$
7

 
$
4

 
$
—

 
$
13

Deferred tax asset valuation allowance
2,386

 
(50
)
 
—

 
—

 
2,336

Year ended December 31, 2010
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
14

 
$
(12
)
 
$
—

 
$
—

 
$
2

Deferred tax asset valuation allowance
2,572

 
(186
)
 
—

 
—

 
2,386

Year ended December 31, 2009
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
42

 
$
2

 
$
—

 
$
(30
)
 
$
14

Deferred tax asset valuation allowance
2,685

 
(113
)
 
—

 
—

 
2,572

_____________
(1)
Represents write-offs of accounts considered to be uncollectible and previously reserved.
Summary of Significant Accounting Policies (Policies)
Consolidation 
Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
Consolidation of OMEC — We were required by U.S. GAAP to adopt new accounting standards for VIEs which became effective January 1, 2010 that 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 U.S. GAAP, we consolidated OMEC effective January 1, 2010. Our Consolidated Financial Statements for the year ended December 31, 2009 present our investment in OMEC’s revenues and expenses under the equity method of accounting. We made no other changes to our group of subsidiaries that we consolidate as a result of the adoption of these new standards. See Note 5 for further discussion of accounting for our VIEs.
Equity Method Investments 
We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, and Whitby, a 50% equity interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement. See Note 5 for further discussion of our VIEs and unconsolidated investments.
We consolidate our VIEs where we determine that we have 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. We have determined 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 determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes 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, and 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 is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
•
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
•
evaluate if an entity is a VIE and whether we are the primary beneficiary whenever 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 or when there are other changes in the powers held by individual variable interest holders.
Revisions 
We have revised the amount reported on our Consolidated Statement of Operations as loss on interest rate derivatives by approximately $24 million for the year ended December 31, 2010. The offsetting reduction was to the amount reported as interest expense. This revision had no impact on our financial condition, results of operations or cash flows. See Note 8 for further information about our interest rate swaps formerly hedging our First Lien Credit Facility.
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 Financial Statements. Actual results could differ from those estimates.
Fair Value of Financial Instruments and Derivatives 
The carrying values of 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, 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 to be creditworthy 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 counterparties, including our receivable, commodity and derivative transactions. 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 derivative 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.
Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:
•
financial institutions and trading companies;
•
regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and
•
oil, natural gas, chemical and other energy-related industrial companies.
We have concentrations of credit risk with a few of our commercial customers relating to our sales of power, steam and hedging and optimization activities. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties for our commodity and derivative transactions. Currently, certain of our marketing counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements.
We also have unfunded credit exposure to several European financial institutions related to our Russell City Project Debt and Los Esteros Project Debt. These financial institutions continue to provide construction funding in accordance with the terms of the debt agreements. Should one or all of these financial institutions be unable to perform under their obligations, it would not have a material adverse effect on our financial position or results of operations. See Note 6 for a further discussion of our Russell City Project Debt and Los Esteros Project Debt.
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 December 31, 2011 and 2010, we had cash and cash equivalents of $306 million and $269 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 Balance Sheets and Statements of Cash Flows.
Accounts Receivable and Payable 
Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance accounts after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.
The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.
Inventory 
At December 31, 2011 and 2010, we had inventory of $294 million and $262 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 are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
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 previously subject to first priority liens under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan and certain of our interest rate swap agreements. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our 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 Notes, Corporate Revolving Facility, Term Loan and New Term Loan. See Note 9 for a further discussion on our amounts and use of collateral.
Deferred Financing Costs 
Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write off the original deferred financing costs and capitalize the new issuance costs, or continue to amortize the original deferred financing costs and immediately expense the new issuance costs.
Property, Plant and Equipment, Net 
Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, repairs or replacements when they appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and accounted for the assets under purchase accounting. All well costs, except well workovers, have been capitalized since our purchase date.
We depreciate our assets under the straight line method over the shorter of their estimated useful life or lease term using an estimated salvage value which approximates 10% of the depreciable cost basis for our power plant assets where we own the land or have a favorable option to purchase the land at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for our rotable equipment. During 2009, we reviewed our accounting policies related to depreciation including our estimates of useful lives. We determined changing from composite depreciation to component depreciation for our rotable natural gas-fired power plant assets, and changing our Geysers Assets depreciation from the units of production method to the straight line method was preferable under U.S. GAAP. We also revised our estimates of useful lives. See Note 4 for further discussion regarding our changes in depreciation, changes in useful lives and the effective date of our changes.
Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and a gain or loss is recorded as plant operating expense.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments) 
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
During 2011, we did not record any impairment losses. During 2010, we impaired approximately $95 million related to South Point (see Note 3 for further information related to our acquisition of the South Point lease and subsequent impairment of our South Point assets) and development costs of approximately $21 million associated with two development projects that originated prior to our Chapter 11 bankruptcy proceedings. We continued to market these projects after our Effective Date, but during 2010 we determined that their continued development was unlikely. During 2009, we had miscellaneous impairments of approximately $4 million.
Asset Retirement Obligation 
We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2011 and 2010, our asset retirement obligation liabilities were $27 million and $51 million, respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return. Our asset retirement obligation liabilities for the year ended December 31, 2011 decreased by $24 million primarily related to a revision in the expected settlement dates of the asset retirement obligations on several of our power plants.
Revenue Recognition 
Our operating revenues are composed of the following:
•
power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation including capacity payments received from PJM capacity auctions, variable payments for power and steam, which are related to generation, host steam and RECs from our Geysers Assets, and other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues;
•
realized and unrealized revenues from derivative instruments as a result of our marketing, hedging and optimization activities; and
•
other service revenues.
Power and Steam
Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. Such contracts often meet the criteria of a derivative but are generally eligible for and designated under the normal purchase normal sale exemption. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.
With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the variable payment as revenue but do not record any fuel and purchased energy expense.
Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
Leases — Contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract.
Accounting for Derivative Instruments 
We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. 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 are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. See Note 8 for a further discussion on our accounting for derivatives.
Fuel and Purchased Energy Expense 
Fuel and purchased energy expense is composed of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, and the cost of power and natural gas purchased from third parties for marketing, hedging and optimization activities as well as realized and unrealized mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas contracts including financial gas transactions economically hedging anticipated future power sales that do not qualify for hedge accounting treatment.
Plant Operating Expense 
Plant operating expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance, insurance and property taxes. We recognize these expenses when the service is performed or in the period in which the expense relates.
Income Taxes 
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. See Note 10 for a further discussion on our income taxes.
Earnings (Loss) per Share 
Basic earnings (loss) per share is calculated using the weighted average shares outstanding during the period and includes restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted earnings (loss) per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method. See Note 11 for a further discussion of our earnings (loss) per share.
Stock-Based Compensation 
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model to estimate the fair value of our employee stock options on the grant date. The Black-Scholes option-pricing model and the Monte Carlo simulation model take into account certain variables, which are further explained in Note 12.
Summary of Significant Accounting Policies (Tables)
Schedule of Components of Restricted Cash 
The table below represents the components of our restricted cash as of December 31, 2011 and 2010 (in millions):
 
 
2011
 
2010
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
11

 
$
42

 
$
53

 
$
44

 
$
25

 
$
69

Rent reserve
—

 
—

 
—

 
22

 
5

 
27

Construction/major maintenance
33

 
10

 
43

 
35

 
14

 
49

Security/project/insurance
79

 
—

 
79

 
75

 
7

 
82

Other
16

 
3

 
19

 
19

 
2

 
21

Total
$
139

 
$
55

 
$
194

 
$
195

 
$
53

 
$
248

___________
(1)
At both December 31, 2011 and 2010, debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.
Schedule of Total Contractual Future Minimum Lease Receipts 
act.
The total contractual future minimum lease receipts for these contracts are as follows (in millions
The following is a schedule by year of future minimum lease payments under capital leases and failed sale-leaseback transactions together with the present value of the net minimum lease payments as of December 31, 2011 (in millions):
 
Sale-Leaseback Transactions(1)
 
Capital Lease
 
Total
2012
$
41

 
$
40

 
$
81

2013
38

 
38

 
76

2014
26

 
39

 
65

2015
25

 
37

 
62

2016
25

 
40

 
65

Thereafter
143

 
200

 
343

Total minimum lease payments
298

 
394

 
692

Less: Amount representing interest
110

 
170

 
280

Present value of net minimum lease payments
$
188

 
$
224

 
$
412

____________
(1)
Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
Acquisitions, Divestitures and Discontinued Operations (Tables)
12 Months Ended
Dec. 31, 2011
Dec. 8, 2010
Acquisitions, Divestitures and Discontinued Operations [Abstract]
 
 
Schedule of Business Acquisitions, by Acquisition
Text Block 
 
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures
Text Block 
 
Losses Due To Acquisition
 
Text Block 
Schedule of Business Acquisitions, by Acquisition 
During the second quarter of 2011, we finalized the valuations of the net assets acquired in the Conectiv Acquisition which is summarized in the following table (in millions). We did not record any material valuation adjustments during the first half of 2011, and we did not recognize any goodwill as a result of this acquisition.

Consideration
$
1,640

 
 
Final values of identifiable assets acquired and liabilities assumed:
 
Assets:
 
Current assets
$
78

Property, plant and equipment, net
1,574

Other long-term assets
85

Total assets acquired
1,737

Liabilities:
 
Current liabilities
46

Long-term liabilities
51

Total liabilities assumed
97

Net assets acquired
$
1,640

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures 
The table below presents the components of our discontinued operations for the periods presented (in millions):
 
 
2010
 
2009
Operating revenues
 
$
92

 
$
101

Gain on disposal of discontinued operations
 
209

 
—

Income from discontinued operations before taxes
 
43

 
35

Less: Income tax expense
 
59

 
—

Discontinued operations, net of tax
 
$
193

 
$
35

Losses Due To Acquisition 
We recorded a total pre-tax loss of approximately $125 million on our Consolidated Statement of Operations for the year ended December 31, 2010 for this transaction, which was recorded as shown below (in millions):
 
Broad River: debt extinguishment costs
$
30

South Point: impairment loss
95

Total loss recorded for this transaction
$
125

Property, Plant and Equipment, Net (Tables)
Components of Property, Plant and Equipment
As of December 31, 2011 and 2010, the components of property, plant and equipment, are stated at cost less accumulated depreciation as follows (in millions):
 
2011
 
2010
Buildings, machinery and equipment
$
15,074

 
$
14,669

Geothermal properties
1,163

 
1,102

Other
156

 
182

 
16,393

 
15,953

Less: Accumulated depreciation
4,158

 
3,690

 
12,235

 
12,263

Land
91

 
93

Construction in progress
693

 
622

Property, plant and equipment, net
$
13,019

 
$
12,978

Variable Interest Entities and Unconsolidated Investments (Tables)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2009
Variable Interest Entities and Unconsolidated Investments [Abstract]
 
 
Income/Loss from Unconsolidated Investments in Power Plants and Distributions
Text Block 
 
Equity Method Investment Summarized Financial Information Income Statement
 
Text Block 
Schedule of Equity Method Investments
Text Block 
 
Income/Loss from Unconsolidated Investments in Power Plants and Distributions 
Our equity interest in the net income from OMEC for the year ended December 31, 2009, and both Greenfield LP and Whitby for the years ended December 31, 2011, 2010 and 2009 are recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the years indicated (in millions):
 
(Income) from Unconsolidated
Investments in Power Plants
 
Distributions
 
2011
 
2010
 
2009
 
2011
 
2010
 
2009
OMEC(1)
$
—

 
$
—

 
$
(32
)
 
$
—

 
$
—

 
$
9

Greenfield LP
(12
)
 
(8
)
 
(16
)
 
2

 
6

 
9

Whitby
(9
)
 
(8
)
 
(2
)
 
4

 
5

 
2

Total
$
(21
)
 
$
(16
)
 
$
(50
)
 
$
6

 
$
11

 
$
20

___________
(1)
OMEC was consolidated effective January 1, 2010. See Note 2.
Equity Method Investment Summarized Financial Information Income Statement 
The condensed combined financial statements for our unconsolidated subsidiaries for the period in which OMEC was a significant unconsolidated subsidiary and was accounted for under the equity method of accounting is presented below (in millions):
Condensed Combined Statement of Operations
of Our Unconsolidated Subsidiaries
For the Year Ended December 31, 2009
 
 
2009
Revenues
$
256

Operating expenses
195

Income from operations
61

Interest (income) expense
2

Other (income) expense, net
5

Net income
$
54

Schedule of Equity Method Investments 
At December 31, 2011 and 2010, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of December 31, 2011
 
2011
 
2010
Greenfield LP
50%
 
72

 
77

Whitby
50%
 
8

 
3

Total investments
 
 
$
80

 
$
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 Balance Sheets. At December 31, 2011 and 2010, equity method investee debt was approximately $462 million and $494 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $231 million and $247 million at December 31, 2011 and 2010, respectively.
Our equity
Debt (Tables)
Schedule of Long-term Debt Instruments 
Our debt at December 31, 2011 and 2010, was as follows (in millions):
 
2011
 
2010
First Lien Notes(1)
$
5,892

 
$
4,691

Project financing, notes payable and other(2)(3)
1,691

 
1,922

Term Loan and New Term Loan(2)(4)
1,646

 
—

CCFC Notes
972

 
965

Capital lease obligations
224

 
236

NDH Project Debt(4)
—

 
1,258

First Lien Credit Facility(1)
—

 
1,184

Total debt
10,425

 
10,256

Less: Current maturities
104

 
152

Debt, net of current portion
$
10,321

 
$
10,104

_____________
(1)
On January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed below.
(2)
On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described below.
(3)
On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City and on August 23, 2011, we closed on the $373 million Los Esteros Project Debt to fund the upgrade of our Los Esteros Critical Energy Facility, both further described below.
(4)
On March 9, 2011, we borrowed $1.3 billion under the Term Loan and repaid and terminated the NDH Project Debt as discussed below.
Schedule of Maturities of Long-term Debt 
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2011, are as follows (in millions):
 
2012
$
104

2013
135

2014
392

2015
164

2016
1,177

Thereafter
8,496

Total debt
10,468

Less: Discount
43

Total
$
10,425

First Lien Notes 
Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2011
 
2010
 
2011
 
2010
2017 First Lien Notes
$
1,200

 
$
1,200

 
7.5
%
 
7.5
%
2019 First Lien Notes
400

 
400

 
8.2

 
8.2

2020 First Lien Notes
1,092

 
1,091

 
8.1

 
8.1

2021 First Lien Notes
2,000

 
2,000

 
7.7

 
7.7

2023 First Lien Notes(2)
1,200

 
—

 
8.0

 
—

Total First Lien Notes
$
5,892

 
$
4,691

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
(2)
On January 14, 2011, we issued $1.2 billion in aggregate principal amount of 7.875% senior secured notes due 2023 in a private placement. Interest on the 2023 First Lien Notes is payable semi-annually on January 15 and July 15 of each year, beginning on July 15, 2011. The 2023 First Lien Notes will mature on January 15, 2023.
Project Financing Notes Payable and Other 
The components of our project financing, notes payable and other are (in millions, except for interest rates):
 
Outstanding at
December 31,
 
Weighted Average
Effective Interest Rates(1)
 
 
2011
 
2010
 
2011
 
2010
 
Steamboat due 2017
$
437

 
$
445

 
6.6
%
 
6.6
%
 
OMEC due 2019
355

 
364

 
6.8

 
6.8

 
Russell City
244

 
—

 
4.1

 
—

 
Calpine BRSP due 2014
232

 
297

 
5.7

 
5.7

 
Pasadena(2)
185

 
208

 
8.8

 
8.6

 
Bethpage Energy Center 3, LLC due 2020-2025(3)
98

 
103

 
7.0

 
7.0


Los Esteros
83

 
—

 
3.8

 
—

 
Gilroy note payable due 2014
49

 
64

 
10.6

 
10.6

 
Metcalf(4)
—

 
251

 
—

 
6.9

 
Deer Park(4)
—

 
99

 
—

 
7.7

 
Gilroy Energy Center, LLC
—

 
38

 
—

 
7.3

 
Whitby Holdings(5)
—

 
26

 
—

 
9.1

 
GEC Holdings, LLC preferred interest
—

 
14

 
—

 
16.6

 
Other
8

 
13

 
—

 
—

 
Total
$
1,691

 
$
1,922

 
 
 
 
 
_____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
(2)
Represents a sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
(3)
Represents a weighted average of first and second lien loans for the weighted average effective interest rates.
(4)
On June 17, 2011, we repaid Metcalf and Deer Park project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described above.
(5)
The Whitby Holdings debt was purchased from a third party in 2011.
Schedule of Future Minimum Lease Payments for Capital Leases 
act.
The total contractual future minimum lease receipts for these contracts are as follows (in millions
The following is a schedule by year of future minimum lease payments under capital leases and failed sale-leaseback transactions together with the present value of the net minimum lease payments as of December 31, 2011 (in millions):
 
Sale-Leaseback Transactions(1)
 
Capital Lease
 
Total
2012
$
41

 
$
40

 
$
81

2013
38

 
38

 
76

2014
26

 
39

 
65

2015
25

 
37

 
62

2016
25

 
40

 
65

Thereafter
143

 
200

 
343

Total minimum lease payments
298

 
394

 
692

Less: Amount representing interest
110

 
170

 
280

Present value of net minimum lease payments
$
188

 
$
224

 
$
412

____________
(1)
Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
Schedule of Line of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities as of December 31, 2011 and 2010 (in millions):
 
2011
 
2010
Corporate Revolving Facility(1)
$
440

 
$
443

CDHI(2)
193

 
165

NDH Project Debt credit facility(3)
—

 
34

Various project financing facilities
130

 
69

Total
$
763

 
$
711

__________
(1)
When we entered into our $1.0 billion Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced with letters of credit issued under our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during 2011.
(2)
On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.
(3)
We repaid and terminated the NDH Project Debt on March 9, 2011
Fair Value, by Balance Sheet Grouping 
 
2011
 
2010
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
6,219

 
$
5,892

 
$
4,695

 
$
4,691

Project financing, notes payable and other(1)
1,467

 
1,504

 
1,673

 
1,708

Term Loan and New Term Loan
1,615

 
1,646

 
—

 
—

CCFC Notes
1,070

 
972

 
1,067

 
965

NDH Project Debt
—

 
—

 
1,303

 
1,258

First Lien Credit Facility
—

 
—

 
1,182

 
1,184

Total
$
10,371

 
$
10,014

 
$
9,920

 
$
9,806

____________
(1)
Excludes leases that are accounted for as failed sale-leaseback transactions under U.S. GAAP and included in our project financing, notes payable and other balance
Assets and Liabilities with Recurring Fair Value Measurements (Tables)
Fair Value, Measurement Inputs, Disclosure 
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010, 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 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 futures 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 futures contracts
899

 
—

 
—

 
899

Commodity forward contracts(2)
—

 
184

 
20

 
204

Interest rate swaps
—

 
320

 
—

 
320

Total liabilities
$
933

 
$
504

 
$
20

 
$
1,457

 
 
 
 
 
 
 
 
 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2010
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,297

 
$
—

 
$
—

 
$
1,297

Margin deposits
162

 
—

 
—

 
162

Commodity instruments:
 
 
 
 
 
 
 
Commodity futures contracts
550

 
—

 
—

 
550

Commodity forward contracts(2)
—

 
287

 
54

 
341

Interest rate swaps
—

 
4

 
—

 
4

Total assets
$
2,009

 
$
291

 
$
54

 
$
2,354

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
6

 
$
—

 
$
—

 
$
6

Commodity instruments:
 
 
 
 
 
 
 
Commodity futures contracts
574

 
—

 
—

 
574

Commodity forward contracts(2)
—

 
119

 
24

 
143

Interest rate swaps
—

 
371

 
—

 
371

Total liabilities
$
580

 
$
490

 
$
24

 
$
1,094

___________
(1)
As of December 31, 2011 and 2010, we had cash equivalents of $1,249 million and $1,094 million included in cash and cash equivalents and $166 million and $203 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation 
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 years ended December 31, 2011, 2010 and 2009 (in millions):
 
2011
 
2010
 
2009
Balance, beginning of period
$
30

 
$
38

 
$
105

Realized and unrealized gains (losses):
 
 
 
 
 
Included in net income:
 
 
 
 
 
Included in operating revenues(1)
5

 
7

 
14

Included in fuel and purchased energy expense(2)
—

 
—

 
5

Included in OCI
2

 
2

 
(4
)
Purchases, issuances and settlements:
 
 
 
 
 
Settlements
(18
)
 
(20
)
 
(48
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
Transfers into level 3(4)
(2
)
 
—

 
—

Transfers out of level 3(5)
—

 
3

 
(34
)
Balance, end of period
$
17

 
$
30

 
$
38

Change in unrealized gains relating to instruments still held at end of period(2)
$
5

 
$
7

 
$
19

___________
(1)
For power contracts and Heat Rate swaps and options, included on our Consolidated Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Statements of Operations.
(3)
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 1 during the years ended December 31, 2011, 2010 and 2009.
(4)
We had $2 million in losses transferred out of level 2 into level 3 for the year ended December 31, 2011, due to changes in market liquidity in various power and natural gas markets.There were no significant transfers into level 3 for the years ended December 31, 2010 and 2009.
(5)
There were no significant transfers out of level 3 for the year ended 2011. We had $3 million in losses and $(34) million in (gains) transferred out of level 3 into level 2 for the years ended December 31, 2010 and 2009, respectively, due to changes in market liquidity in various power markets.

Derivative Instruments (Tables)
Schedule of Notional Amounts of Outstanding Derivative Positions 
As of December 31, 2011 and 2010, 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
 
2011
 
2010
Power (MWh)
 
(21
)
 
(50
)
Natural gas (MMBtu)
 
(200
)
 
31

Interest rate swaps(1)
 
$
5,639

 
$
6,171

____________
(1)
Approximately $4.1 billion and $3.3 billion at December 31, 2011 and 2010, respectively, related to variable rate debt that was converted to fixed rate debt in 2011 and 2010.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value 
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2011 and 2010 (in millions):
 
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
)

 
December 31, 2010
 
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
—

 
$
725

 
$
725

Long-term derivative assets
4

 
166

 
170

Total derivative assets
$
4

 
$
891

 
$
895

 
 
 
 
 
 
Current derivative liabilities
$
197

 
$
521

 
$
718

Long-term derivative liabilities
174

 
196

 
370

Total derivative liabilities
$
371

 
$
717

 
$
1,088

Net derivative assets (liabilities)
$
(367
)
 
$
174

 
$
(193
)
Derivative Instrument by Accounting Designation 
 
December 31, 2011
 
December 31, 2010
 
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:
 
 
 
 
 
 
 
Interest rate swaps
$
10

 
$
149

 
$
2

 
$
143

Commodity instruments
51

 
18

 
161

 
52

Total derivatives designated as cash flow hedging instruments
$
61

 
$
167

 
$
163

 
$
195

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$
—

 
$
171

 
$
2

 
$
228

Commodity instruments
1,103

 
1,085

 
730

 
665

Total derivatives not designated as hedging instruments
$
1,103

 
$
1,256

 
$
732

 
$
893

Total derivatives
$
1,164

 
$
1,423

 
$
895

 
$
1,088

Realized Unrealized Gain Loss by Instrument 
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 not designated as hedging instruments and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009 (in millions):
 
 
2011
 
2010
 
2009
Realized gain (loss)
 
 
 
 
 
Interest rate swaps
$
(193
)
 
$
(31
)
 
$
(32
)
Commodity derivative instruments
143

 
114

 
37

Total realized gain (loss)
$
(50
)
 
$
83

 
$
5

 
 
 
 
 
 
Unrealized gain (loss)(1)
 
 
 
 
 
Interest rate swaps
$
55

 
$
(199
)
 
$
8

Commodity derivative instruments
(25
)
 
143

 
79

Total unrealized gain (loss)
$
30

 
$
(56
)
 
$
87

Total mark-to-market activity, net
$
(20
)
 
$
27

 
$
92


___________
(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.
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location 
 
2011
 
2010
 
2009
Realized and unrealized gain (loss)
 
 
 
 
 
Power contracts included in operating revenues
$
(20
)
 
$
(19
)
 
$
7

Natural gas contracts included in fuel and purchased energy expense
138

 
276

 
109

Interest rate swaps included in interest expense
7

 
(7
)
 
(24
)
Loss on interest rate derivatives
(145
)
 
(223
)
 
—

Total mark-to-market activity, net
$
(20
)
 
$
27

 
$
92

Derivatives Designated as Hedges 
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the years ended December 31, 2011 and 2010 (in millions):
 
 
Gains (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(2)
 
Gain (Loss) Reclassified from
AOCI into Income  (Ineffective
Portion)
 
2011
 
2010
 
2011
 
2010
 
2011
 
2010
Interest rate swaps
$
(23
)
 
$
193

 
$
(138
)
(3) 
$
(389
)
(4) 
$
(1
)
 
$
—

Commodity derivative instruments
(71
)
 
(27
)
 
163

(1) 
248

(1) 
(2
)
 
—

Total
$
(94
)
 
$
166

 
$
25

 
$
(141
)
  
$
(3
)
 
$
—

____________
(1)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Statement of Operations.
(2)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $172 million and $122 million at December 31, 2011 and 2010, respectively. Our other components of AOCI were not material at December 31, 2011 and 2010.
(3)
Reclassification of losses from OCI to earnings consisted of $32 million in losses from the reclassification of interest rate contracts due to settlement, $15 million in losses from terminated interest rate contracts due to the repayment of project debt in 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans.
(4)
Reclassification of losses from OCI to earnings consisted of $183 million in losses from the reclassification of interest rate contracts due to settlement and $206 million in losses from interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans.
Use of Collateral (Tables)
Schedule of Collateral
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 December 31, 2011 and 2010 (in millions):
 
2011
 
2010
Margin deposits(1)
$
140

 
$
162

Natural gas and power prepayments
42

 
43

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
182

 
$
205

 
 
 
 
Letters of credit issued(3)
$
581

 
$
588

First priority liens under power and natural gas agreements(4)
1

 
—

First priority liens under interest rate swap agreements
318

 
391

Total letters of credit and first priority liens with our counterparties
$
900

 
$
979

 
 
 
 
Margin deposits held by us posted by our counterparties(1)(5)
$
34

 
$
6

Letters of credit posted with us by our counterparties
—

 
66

Total margin deposits and letters of credit posted with us by our counterparties
$
34

 
$
72

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation.
(2)
At December 31, 2011 and 2010, $162 million and $183 million, respectively, were included in margin deposits and other prepaid expense and $20 million and $22 million were included in other assets at December 31, 2011 and 2010, respectively, on our Consolidated Balance Sheets.
(3)
When we entered into our Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued under the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit issued under our Corporate Revolving Facility used for our commodity procurement and risk management activities as of December 31, 2010 include those that were back-stopped of approximately $63 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011.
(4)
At December 31, 2010, the fair value of our commodity derivative instruments collateralized by first priority liens was an asset of $193 million; therefore, there was no collateral exposure at December 31, 2010.
(5)
Included in other current liabilities on our Consolidated Balance Sheets.
Income Taxes Income Taxes (Tables)
Schedule of Income before Income Tax, Domestic and Foreign 
The jurisdictional components of income (loss) from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2011, 2010 and 2009, are as follows (in millions):
 
2011
 
2010
 
2009
U.S.
$
(232
)
 
$
(226
)
 
$
116

International
20

 
(4
)
 
13

Total
$
(212
)
 
$
(230
)
 
$
129

Schedule of Components of Income Tax Expense (Benefit) 
The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2011, 2010 and 2009, consisted of the following (in millions):
 
2011
 
2010
 
2009
Current:
 
 
 
 
 
Federal
$
(16
)
 
$
(1
)
 
$
(2
)
State
12

 
10

 
(2
)
Foreign
3

 
3

 
3

Total current
(1
)
 
12

 
(1
)
Deferred:
 
 
 
 
 
Federal
(33
)
 
(70
)
 
13

State
9

 
—

 
4

Foreign
3

 
(10
)
 
(1
)
Total deferred
(21
)
 
(80
)
 
16

Total income tax expense (benefit)
$
(22
)
 
$
(68
)
(1) 
$
15

_________
(1)
Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI.
Schedule of Effective Income Tax Rate Reconciliation 
A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2011, 2010 and 2009, is as follows:
 
2011
 
2010
 
2009
Federal statutory tax expense (benefit) rate
(35.0
)%
 
(35.0
)%
 
35.0
 %
State tax expense (benefit), net of federal benefit
6.5

 
2.8

 
1.0

Depletion in excess of basis
—

 
(1.3
)
 
—

Valuation allowances against future tax benefits
56.7

 
33.6

 
(139.2
)
Valuation allowances related to reconsolidation of CCFC
(36.0
)
 
—

 
—

Foreign taxes
(0.9
)
 
9.9

 
(9.2
)
Non-deductible reorganization items
0.5

 
0.3

 
1.3

Income from cancellation of indebtedness
—

 
—

 
69.0

Intraperiod allocation
19.9

 
(40.1
)
 
45.4

Bankruptcy settlement
(15.7
)
 
—

 
—

Change in unrecognized tax benefits
(6.6
)
 
0.6

 
1.4

Permanent differences and other items
0.2

 
(0.4
)
 
6.9

Effective income tax expense (benefit) rate
(10.4
)%
 
(29.6
)%
 
11.6
 %
Schedule of Deferred Tax Assets and Liabilities 
The components of the deferred income taxes as of December 31, 2011 and 2010, are as follows (in millions):
 
2011
 
2010
Deferred tax assets:
 
 
 
NOL and credit carryforwards
$
3,290

 
$
3,138

Taxes related to risk management activities and derivatives
58

 
18

Reorganization items and impairments
318

 
422

Foreign capital losses
24

 
25

Other differences
26

 
12

Deferred tax assets before valuation allowance
3,716

 
3,615

Valuation allowance
(2,336
)
 
(2,386
)
Total deferred tax assets
1,380

 
1,229

Deferred tax liabilities: property, plant and equipment
(1,364
)
 
(1,280
)
Net deferred tax asset (liability)
16

 
(51
)
Less: Current portion deferred tax asset (liability)
(2
)
 
(4
)
Less: Non-current deferred tax asset
18

 
30

Deferred income tax liability, non-current
$
—

 
$
(77
)
Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation 
The following table details the effects of our intraperiod tax allocations for the year ended December 31, 2011, 2010 and 2009 (in millions).
 
2011
 
2010
 
2009
Intraperiod tax allocation expense (benefit) included in continuing operations
$
42

 
$
(86
)
 
$
43

Intraperiod tax allocation expense (benefit) included in discountinued operations
$
—

 
$
59

 
$
—

Intraperiod tax allocation expense (benefit) included in OCI
$
(45
)
 
$
27

 
$
(43
)
Schedule of Income Tax Contingencies 
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2011, 2010 and 2009, is as follows (in millions):
 
2011
 
2010
 
2009
Balance, beginning of period
$
(88
)
 
$
(98
)
 
$
(90
)
Increases related to prior year tax positions
—

 
(1
)
 
(11
)
Decreases related to prior year tax positions
1

 
11

 
2

Settlements
—

 
—

 
1

Decrease related to lapse of statute of limitations
13

 
—

 
—

Balance, end of period
$
(74
)
 
$
(88
)
 
$
(98
)
Earnings (Loss) per Share (Tables)
Schedule of Weighted Average Number of Shares 
Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the years ended December 31, 2011, 2010 and 2009, are as follows (shares in thousands):
 
2011
 
2010
 
2009
Diluted weighted average shares calculation:
 
 
 
 
 
Weighted average shares outstanding (basic)
485,381

 
486,044

 
485,659

Share-based awards
—

 
1,250

 
660

Weighted average shares outstanding (diluted)
485,381

 
487,294

 
486,319

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share 
We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2011, 2010 and 2009 because they were anti-dilutive (shares in thousands):
 
2011
 
2010
 
2009
Share-based awards
15,260

 
14,883

 
13,158

Stock-Based Compensation (Tables)
Schedule of Non-Qualified Stock Option Activity 
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2011, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2010
17,164,890

 
$
17.44

 
5.6

 
$
8

Granted
953,467

 
$
14.27

 
 
 
 
Exercised
7,554

 
$
11.66

 
 
 
 
Forfeited
197,316

 
$
13.04

 
 
 
 
Expired
247,585

 
$
17.56

 
 
 
 
Outstanding — December 31, 2011
17,665,902

 
$
17.32

 
4.8

 
$
26

Exercisable — December 31, 2011
8,297,284

 
$
19.49

 
4.6

 
$
2

Vested and expected to vest – December 31, 2011
17,377,738

 
$
17.39

 
4.7

 
$
25

Schedule of Assumptions Used to Estimate Fair Value for Options 
Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
2011
 
2010
 
2009
 
Expected term (in years)(1)
6.5

 
4.0 – 6.5

 
6.0 – 6.5

 
Risk-free interest rate(2)
1.7 – 3.2

%
1.3 – 3.3

%
2.3 – 2.9

%
Expected volatility(3)
31.2 – 44.9

%
31.4   – 37.6

%
52.1 – 73.0

%
Dividend yield(4)
—

 
—

 
—

 
Weighted average grant-date fair value (per option)
$
5.49

 
$
1.98

 
$
5.67

 
___________
(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 stock options.
(4)
We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future.
Schedule of Restricted Stock and Restricted Stock Unit Activity 
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended December 31, 2011, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2010
2,683,117

2,046,599

$
11.16

Granted
1,636,026

1,475,992

$
14.37

Forfeited
322,034

400,141

$
12.32

Vested
486,751

439,333

$
14.41

Nonvested — December 31, 2011
3,510,358

 
$
12.10

Capital Structure (Tables)
Schedule of Common Stock Activity
The table below summarizes our common stock activity for the years ended December 31, 2011, 2010 and 2009.
 
Shares
Issued
 
Shares
Held in
Treasury
 
Shares
Held in
Reserve
 
Inter-
Creditor
Disputes
 
Total
Balance, December 31, 2008
429,025,057

 
(65,032
)
 
48,162,203

 
9,752,261

 
486,874,489

Resolution of claims/inter-creditor disputes
13,167,420

 
—

 
(3,415,159
)
 
(9,752,261
)
 
—

Shares issued under Calpine Equity Incentive Plans
1,133,350

 
(262,540
)
 
—

 
—

 
870,810

Balance, December 31, 2009
443,325,827

 
(327,572
)
 
44,747,044

 
—

 
487,745,299

Resolution of claims
488,612

 
—

 
(488,612
)
 
—

 
—

Shares issued under Calpine Equity Incentive Plans
1,068,917

 
(120,586
)
 
—

 
—

 
948,331

Balance, December 31, 2010
444,883,356

 
(448,158
)
 
44,258,432

 
—

 
488,693,630

Resolution of claims
44,258,432

 
—

 
(44,258,432
)
 
—

 
—

Shares issued under Calpine Equity Incentive Plans
1,327,027

 
(139,846
)
 
—

 
—

 
1,187,181

Share repurchase program
—

 
(8,137,073
)
 
—

 
—

 
(8,137,073
)
Balance, December 31, 2011
490,468,815

 
(8,725,077
)
 
—

 
—

 
481,743,738

Commitments and Contingencies (Tables)
Schedule of Future Minimum Rental Payments for Power Plant and Land and Other Operating Leases 
Future minimum lease payments under these leases are as follows (in millions):
 
Initial
Year
 
2012
 
2013
 
2014
 
2015
 
2016
 
Thereafter
 
Total
Land and other operating leases
various
 
$
12

 
$
11

 
$
11

 
$
14

 
$
14

 
$
431

 
$
493

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
7

 
$
3

 
$
—

 
$
—

 
$
—

 
$
17

KIAC
2000
 
24

 
24

 
24

 
23

 
22

 
74

 
191

Total power plant leases
 
 
$
31

 
$
31

 
$
27

 
$
23

 
$
22

 
$
74

 
$
208

Total leases
 
 
$
43

 
$
42

 
$
38

 
$
37

 
$
36

 
$
505

 
$
701

Schedule of Future Minimum Lease Payments for Office and Equipment Leases 
Future minimum lease payments under these leases are as follows (in millions):
2012
$
13

2013
12

2014
10

2015
10

2016
9

Thereafter
32

Total
$
86

Schedule of Guarantor Obligations 
At December 31, 2011, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in millions):
Guarantee Commitments
 
2012
 
2013
 
2014
 
2015
 
2016
 
Thereafter
 
Total
Guarantee of subsidiary debt(1)
 
$
76

 
$
73

 
$
272

 
$
36

 
$
36

 
$
236

 
$
729

Standby letters of credit(2)(4)
 
669

 
45

 
—

 
—

 
—

 
49

 
763

Surety bonds(3)(4)(5)
 
—

 
—

 
—

 
—

 
—

 
4

 
4

 Guarantee of subsidiary operating lease payments(4)
 
7

 
7

 
3

 
—

 
—

 
—

 
17

Total
 
$
752

 
$
125

 
$
275

 
$
36

 
$
36

 
$
289

 
$
1,513

____________
(1)
Represents Calpine Corporation guarantees of certain project debt, power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.
(2)
The standby letters of credit disclosed above represent those disclosed in Note 6.
(3)
The majority of surety bonds do not have expiration or cancellation dates.
(4)
These are contingent off balance sheet obligations.
(5)
As of December 31, 2011, $4 million of cash collateral is outstanding related to these bonds.
Segment and Significant Customer Information (Tables)
Schedule of Financial Data for Segments
The tables below show our financial data for our segments for the periods indicated (in millions).
 
Year Ended December 31, 2011
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
2,372

 
$
2,306

 
$
1,336

 
$
786

 
$
—

 
$
6,800

Intersegment revenues
12

 
23

 
7

 
135

 
(177
)
 
—

Total operating revenues
$
2,384

 
$
2,329

 
$
1,343

 
$
921

 
$
(177
)
 
$
6,800

Commodity Margin
$
1,061

 
$
469

 
$
704

 
$
240

 
$
—

 
$
2,474

Add: Mark-to-market commodity activity, net and other(1)(2)
113

 
(102
)
 
(13
)
 
1

 
(32
)
 
(33
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
380

 
235

 
177

 
141

 
(29
)
 
904

Depreciation and amortization expense
192

 
135

 
138

 
90

 
(5
)
 
550

Sales, general and other administrative expense
43

 
43

 
24

 
22

 
(1
)
 
131

Other operating expenses(3)
41

 
3

 
30

 
5

 
(2
)
 
77

(Income) from unconsolidated investments in power plants
—

 
—

 
(21
)
 
—

 
—

 
(21
)
Income (loss) from operations
518

 
(49
)
 
343

 
(17
)
 
5

 
800

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
751

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
145

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
115

Loss before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
(211
)

 
Year Ended December 31, 2010
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
2,525

 
$
2,162

 
$
978

 
$
880

 
$
—

 
$
6,545

Intersegment revenues
12

 
22

 
6

 
138

 
(178
)
 
—

Total operating revenues
$
2,537

 
$
2,184

 
$
984

 
$
1,018

 
$
(178
)
 
$
6,545

Commodity Margin
$
1,080

 
$
504

 
$
535

 
$
272

 
$
—

 
$
2,391

Add: Mark-to-market commodity activity, net and other(1)
69

 
89

 
21

 
22

 
(30
)
 
171

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
351

 
285

 
138

 
123

 
(29
)
 
868

Depreciation and amortization expense
207

 
150

 
111

 
109

 
(7
)
 
570

Sales, general and other administrative expense
55

 
38

 
45

 
12

 
1

 
151

Other operating expenses(3)
59

 
2

 
28

 
4

 
(2
)
 
91

Impairment losses
97

 
—

 
—

 
19

 
—

 
116

(Gain) on sale of assets, net
—

 
(119
)
 
—

 
—

 
—

 
(119
)
(Income) from unconsolidated investments in power plants
—

 
—

 
(16
)
 
—

 
—

 
(16
)
Income from operations
380

 
237

 
250

 
27

 
7

 
901

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
802

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
223

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
106

Loss before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
(230
)

 
Year Ended December 31, 2009
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
3,311

 
$
1,816

 
$
558

 
$
778

 
$
—

 
$
6,463

Intersegment revenues
28

 
63

 
16

 
97

 
(204
)
 
—

Total operating revenues
$
3,339

 
$
1,879

 
$
574

 
$
875

 
$
(204
)
 
$
6,463

Commodity Margin
$
1,245

 
$
644

 
$
268

 
$
304

 
$
—

 
$
2,461

Add: Mark-to-market commodity activity, net and other(1)
143

 
(40
)
 
46

 
(5
)
 
(44
)
 
100

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
408

 
232

 
91

 
134

 
3

 
868

Depreciation and amortization expense
188

 
129

 
67

 
80

 
(8
)
 
456

Sales, general and other administrative expense
66

 
63

 
18

 
27

 
—

 
174

Other operating expenses(3)
73

 
14

 
30

 
11

 
(32
)
 
96

Impairment losses
4

 
—

 
—

 
—

 
—

 
4

(Income) from unconsolidated investments in power plants
(32
)
 
—

 
(18
)
 
—

 
—

 
(50
)
Income from operations
681

 
166

 
126

 
47

 
(7
)
 
1,013

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
799

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
89

Income before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
125

__________
(1)
Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009, as well as a non-cash gain from amortization of prepaid power sales agreements for the year ended December 31, 2009.
(2)
Includes $12 million of lease levelization and $8 million of contract amortization for the year ended December 31, 2011 related to contracts that became effective in 2011.
(3)
Excludes $10 million, $9 million and $5 million of RGGI compliance and other environmental costs for the years ended December 31, 2011, 2010 and 2009, respectively, which are components of Commodity Margin.
Quarterly Consolidated Financial Data (unaudited) (Tables)
Schedule of Quarterly Consolidated Financial Data (unaudited)
 
Quarter Ended
 
December 31
 
September 30
 
June 30
 
March 31
 
(in millions, except per share amounts)
2011
 
 
 
 
 
 
 
Operating revenues
$
1,459

 
$
2,209

 
$
1,633

 
$
1,499

Income from operations
196

 
403

 
183

 
18

Income (loss) before discontinued operations attributable to Calpine
$
(13
)
 
$
190

 
$
(70
)
 
$
(297
)
Discontinued operations, net of tax expense, attributable to Calpine
—

 
—

 
—

 
—

Net income (loss) attributable to Calpine
$
(13
)
 
$
190

 
$
(70
)
 
$
(297
)
Basic earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Discontinued operations, net of tax expense, attributable to Calpine
—

 
—

 
—

 
—

Net income (loss) attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Discontinued operations, net of tax expense, attributable to Calpine
—

 
—

 
—

 
—

Net income (loss) attributable to Calpine
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
2010
 
 
 
 
 
 
 
Operating revenues
$
1,471

 
$
2,130

 
$
1,430

 
$
1,514

Income from operations
89

 
554

 
108

 
150

Income (loss) before discontinued operations attributable to Calpine
$
(186
)
 
$
198

 
$
(119
)
 
$
(55
)
Discontinued operations, net of tax expense, attributable to Calpine
162

 
19

 
4

 
8

Net income (loss) attributable to Calpine
$
(24
)
 
$
217

 
$
(115
)
 
$
(47
)
Basic earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.38
)
 
$
0.41

 
$
(0.25
)
 
$
(0.11
)
Discontinued operations, net of tax expense, attributable to Calpine
0.33

 
0.04

 
0.01

 
0.01

Net income (loss) attributable to Calpine
$
(0.05
)
 
$
0.45

 
$
(0.24
)
 
$
(0.10
)
Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$
(0.38
)
 
$
0.41

 
$
(0.25
)
 
$
(0.11
)
Discontinued operations, net of tax expense, attributable to Calpine
0.33

 
0.04

 
0.01

 
0.01

Net income (loss) attributable to Calpine
$
(0.05
)
 
$
0.45

 
$
(0.24
)
 
$
(0.10
)
Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Held-to-maturity Securities, Restricted
$ 25 
$ 25 
 
Current
139 
195 
 
Non-current
55 
53 
 
Total
194 
248 
 
Prior Period Reclassification Adjustment [Abstract]
 
 
 
Ownership percentage in equity method investment
50.00% 
 
 
Reclassification adjustment on interest rate swaps
 
24 
 
Cash and cash equivalents subject to project finance facilities and lease agreements
306 
269 
 
Inventory
294 
262 
 
Property, plant and equipment, salvage value (as a percent)
10.00% 
 
 
Property, plant and equipment, salvage value of rotables (as a percent)
0.15% 
 
 
Impairment of long-lived assets held for use
 
95 
 
Impairment loss
0 
116 
4 
Asset retirement obligations
27 
51 
 
Decrease in ARO related to Revision of Expected Settlement Dates
24 
 
 
Debt Service
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
11 
44 
 
Non-current
42 
25 
 
Total
53 
69 
 
Rent Reserve
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
0 
22 
 
Non-current
0 
5 
 
Total
0 
27 
 
Construction Major Maintenance
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
33 
35 
 
Non-current
10 
14 
 
Total
43 
49 
 
Security Project Insurance
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
79 
75 
 
Non-current
0 
7 
 
Total
79 
82 
 
Other
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
16 
19 
 
Non-current
3 
2 
 
Total
19 
21 
 
Greenfield [Member]
 
 
 
Prior Period Reclassification Adjustment [Abstract]
 
 
 
Ownership percentage in equity method investment
50.00% 
 
 
Whitby [Member]
 
 
 
Prior Period Reclassification Adjustment [Abstract]
 
 
 
Ownership percentage in equity method investment
50.00% 
 
 
Two Development Projects [Member]
 
 
 
Prior Period Reclassification Adjustment [Abstract]
 
 
 
Impairment loss
 
$ 21 
 
Summary of Significant Accounting Policies Contractual Future Minimum Lease Receipt Table (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Summary of Significant Accounting Policies [Abstract]
 
Operating Leases, Future Minimum Payments Receivable, Current
$ 300 
Operating Leases, Future Minimum Payments Receivable, in Two Years
287 
Operating Leases, Future Minimum Payments Receivable, in Three Years
286 
Operating Leases, Future Minimum Payments Receivable, in Four Years
288 
Operating Leases, Future Minimum Payments Receivable, in Five Years
291 
Operating Leases, Future Minimum Payments Receivable, Thereafter
1,210 
Operating Leases, Future Minimum Payments Receivable
$ 2,662 
Acquisitions, Divestitures and Discontinued Operations (Details) (USD $)
12 Months Ended 12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 8, 2010
Jul. 2, 2010
Dec. 31, 2011
Conectiv [Member]
Mar. 2, 2011
Conectiv [Member]
Business Acquisition, Purchase Price Allocation [Abstract]
 
 
 
 
 
 
Consideration
 
 
 
$ 1,640,000,000 
 
 
Assets:
 
 
 
 
 
 
Current assets
 
 
 
78,000,000 
 
 
Property, plant and equipment, net
 
 
 
1,574,000,000 
 
 
Other long-term assets
 
 
 
85,000,000 
 
 
Total assets acquired
 
 
 
1,737,000,000 
 
 
Liabilities:
 
 
 
 
 
 
Current liabilities
 
 
 
46,000,000 
 
 
Long-term liabilities
 
 
 
51,000,000 
 
 
Total liabilities assumed
 
 
85,000,000 
97,000,000 
 
 
Net assets acquired
 
 
 
1,640,000,000 
 
 
Number of Power Plants Acquired
 
 
 
18 
 
 
Power generation capacity
11,391 
13,656 
 
 
 
4,491 
Cap on Environmental Remediation Liabilities Acquired
 
 
 
10,000,000 
 
 
Number of Employees Acquired In Acquisition
 
 
 
130 
 
 
Number Of Employees For Which Pension Obligation Was Reduced
 
 
 
31 
 
 
Proceeds from Subsidiary Project Debt
 
 
 
1,300,000,000 
 
 
Variable Interest Entity, Financial or Other Support, Amount
$ 171,000,000 
$ 46,000,000 
 
 
$ 110,000,000 
 
Acquisitions, Divestitures and Discontinued Operations (Acquisition of Broad River and South Point Leases) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 8, 2010
Jul. 2, 2010
Broad River and South Point Leases [Line Items]
 
 
Broad River: debt extinguishment costs
$ 30 
 
South Point: impairment loss
95 
 
Total loss recorded for this transaction
125 
 
Acquisition of Broad River and South Point Leases (Textuals) [Abstract]
 
 
Business Acquisition, Purchase Price Allocation, Notes Payable and Long-term Debt
297 
 
Business Acquisition, Cost of Acquired Entity, Cash Paid
40 
 
Business Acquisition, Purchase Price Allocation, Liabilities Assumed
85 
97 
Debt Eliminated In Acquisition
$ (212)
 
Acquisitions, Divestitures and Discontinued Operations (Sale of Blue Spruce and Rocky Mountain) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2010
Jun. 30, 2010
Mar. 31, 2010
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Dec. 8, 2010
Dec. 6, 2010
Acquisitions, Divestitures and Discontinued Operations [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
 
$ 92 
$ 101 
 
 
Gain on disposal of discontinued operations
 
 
 
 
 
209 
 
 
 
209 
0 
 
 
Income from discontinued operations before taxes
 
 
 
 
 
 
 
 
 
43 
35 
 
 
Less: Income tax expense
 
 
 
 
 
 
 
 
0 
59 
0 
 
 
Discontinued operations, net of tax expense
0 
0 
0 
0 
162 
19 
4 
8 
0 
193 
35 
 
 
Ownership percentage before divestiture of business
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
Proceeds from Divestiture of Business
 
 
 
 
 
 
 
 
 
 
 
 
739 
Other Asset Sales (Textuals) [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Proceeds From Sale Of Undivided Interest In Power Plant Assets
 
 
 
 
 
 
 
 
 
 
 
215 
 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
$ 0 
$ 119 
$ 0 
 
 
Undivided Interest Percentage In Power Plant Asset
 
 
 
 
 
 
 
 
 
 
 
25.00% 
 
Property, Plant and Equipment, Net (Details) (USD $)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Property, Plant and Equipment, Net [Abstract]
 
 
 
Property, Plant and Equipment, Salvage Value, Percentage Rotables Change
0.15% 
 
 
Combined Cycle Power Plant, UsefulLife, Old
35 
 
 
Simple Cycle Power Plant, Useful Life, Old
40 
 
 
Combined Cycle Power Plant, Useful Life, New
37 
 
 
Simple Cycle Power Plant, Useful Life, New
47 
 
 
Depreciation
$ 560,000,000 
$ 568,000,000 
$ 469,000,000 
Rotable Parts, Useful Life, Maximum
18 
 
 
Geysers Power Plant Assets, Useful Life, New
13 
 
 
Daily Water Reinjection
18,000,000 
 
 
Increase In Depreciation Expense For Natural Gas Fired Plants
 
 
28,000,000 
Decrease In Depreciation Expense For Geysers Assets
 
 
3,000,000 
Decrease In Net Income Attributable To Calpine Due To Change In Accounting Estimate
 
 
25,000,000 
Decrease In Basic And Diluted Earnings Per Share Due To Change In Accounting Estimate
 
 
(0.05)
Buildings, machinery and equipment
15,074,000,000 
14,669,000,000 
 
Geothermal properties
1,163,000,000 
1,102,000,000 
 
Other
156,000,000 
182,000,000 
 
Property, Plant and Equipment, Gross
16,393,000,000 
15,953,000,000 
 
Less: Accumulated depreciation
4,158,000,000 
3,690,000,000 
 
Property, Plant and Equipment, Gross, Less Accumulated Depreciation
12,235,000,000 
12,263,000,000 
 
Land
91,000,000 
93,000,000 
 
Construction in progress
693,000,000 
622,000,000 
 
Property, plant and equipment, net
13,019,000,000 
12,978,000,000 
 
Interest Costs, Capitalized During Period
$ 24,000,000 
$ 15,000,000 
$ 8,000,000 
Geysers Steam Extraction And Gathering Assets, Useful Life, New
59 
 
 
Rotable Parts, Useful Life, Minimum
3 
 
 
Variable Interest Entities and Unconsolidated Investments (Consolidation of VIE) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]
 
 
Power generation capacity
11,391 
13,656 
Power generation capacity under construction
584 
1,029 
Equity Method Investment, Ownership Percentage
50.00% 
 
Los Esteros Project [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Power generation capacity
188 
 
Power generation capacity after upgrade
308 
 
Russell City Energy [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investment, Ownership Percentage
75.00% 
 
Minority Interest Ownership Percentage By Noncontrolling Third Party Owners
25.00% 
 
Los Esteros Project [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Debt Instrument, Face Amount
$ 373 
 
Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
$ 80 
$ 80 
Equity Method Investment, Ownership Percentage
50.00% 
 
Greenfield [Member]
 
 
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
72 
77 
Equity Method Investment, Ownership Percentage
50.00% 
 
Whitby [Member]
 
 
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
$ 8 
$ 3 
Equity Method Investment, Ownership Percentage
50.00% 
 
Variable Interest Entities and Unconsolidated Investments (Unconsolidated Investements) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) loss from unconsolidated investments in power plants
$ (21)
$ (16)
$ (50)
Return on investment in unconsolidated subsidiaries
6 
11 
20 
OMEC [Member]
 
 
 
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) loss from unconsolidated investments in power plants
0 1
0 1
(32)1
Return on investment in unconsolidated subsidiaries
0 1
0 1
9 1
Greenfield [Member]
 
 
 
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) loss from unconsolidated investments in power plants
(12)
(8)
(16)
Return on investment in unconsolidated subsidiaries
2 
6 
9 
Whitby [Member]
 
 
 
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) loss from unconsolidated investments in power plants
(9)
(8)
(2)
Return on investment in unconsolidated subsidiaries
$ 4 
$ 5 
$ 2 
Variable Interest Entities and Unconsolidated Investments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
Variable Interest Entity, Financial or Other Support, Amount
$ 171 
$ 46 
NDH Project Debt Credit Facility [Member]
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
Variable Interest Entity, Financial or Other Support, Amount
 
540 
York Energy Center [Member]
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
Variable Interest Entity, Financial or Other Support, Amount
 
$ 110 
Variable Interest Entities and Unconsolidated Investments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2009
Dec. 31, 2011
Dec. 31, 2010
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
 
Equity Method Investment, Summarized Financial Information, Debt
 
$ 462 
$ 494 
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt
 
231 
247 
Power generation capacity
 
11,391 
13,656 
Revenues
256 
 
 
Operating expenses
195 
 
 
Income from operations
61 
 
 
Interest (income) expense
2 
 
 
Other (income) expense, net
5 
 
 
Net income
54 
 
 
Riverside and Otay Mesa [Member]
 
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
 
Power generation capacity
 
1,211 
 
Inland Empire Energy Center [Member]
 
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
 
Power generation capacity
 
775 
 
Put Option Exercise Period
 
15 
 
Minimum [Member] |
Inland Empire Energy Center [Member]
 
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
 
Call Option Exercise Period
 
7 
 
Maximum [Member] |
Inland Empire Energy Center [Member]
 
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
 
Call Option Exercise Period
 
14 
 
Greenfield [Member]
 
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
 
Power generation capacity
 
1,038 
 
Equity Method Investment, Summarized Financial Information, Term Loan Period
 
18 
 
Equity Method Investment, Summarized Financial Information, Term Loan
 
$ 648 
 
Project financing interest rate spread - Canadian LIBOR
 
1.125% 
 
Project financing interest rate spread - Canadian Prime Rate
 
0.125% 
 
Whitby [Member]
 
 
 
Variable Interest Entities and Unconsolidated Investments (Textuals) [Abstract]
 
 
 
Power generation capacity
 
50 
 
Debt (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,425 
$ 10,256 
Debt, Current
104 
152 
Debt, net of current portion
10,321 
10,104 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
5,892 1
4,691 1
First Lien Notes 2017 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,200 
1,200 
Debt Instrument, Interest Rate, Effective Percentage
7.50% 2
7.50% 2
First Lien Notes 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
400 
400 
Debt Instrument, Interest Rate, Effective Percentage
8.20% 2
8.20% 2
First Lien Notes 2020 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,092 
1,091 
Debt Instrument, Interest Rate, Effective Percentage
8.10% 2
8.10% 2
First Lien Notes 2021 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,000 
2,000 
Debt Instrument, Interest Rate, Effective Percentage
7.70% 2
7.70% 2
First Lien Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,200 3
0 3
Debt Instrument, Interest Rate, Effective Percentage
8.00% 2
0.00% 2
Debt Instrument, Interest Rate, Stated Percentage
7.875% 
 
Total First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
5,892 
4,691 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,691 4 5
1,922 4 5
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,646 4 6
0 4 6
Line of Credit [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 1
1,184 1
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
972 
965 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
224 
236 
NDH Project Debt Credit Facility [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 0 6
$ 1,258 6
Debt (Details 2) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Long-term Debt, by Maturity [Abstract]
 
 
2012
$ 104 
 
2013
135 
 
2014
392 
 
2015
164 
 
2016
1,177 
 
Thereafter
8,496 
 
Total debt, gross
10,468 
 
Less: Discount
43 
 
Long-term Debt
$ 10,425 
$ 10,256 
Debt (Details 3) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,425 
$ 10,256 
Steamboat [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
437 
445 
Debt Instrument, Interest Rate, Effective Percentage
6.60% 1
6.60% 1
OMEC [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
355 
364 
Debt Instrument, Interest Rate, Effective Percentage
6.80% 1
6.80% 1
BRSP [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
232 
297 
Debt Instrument, Interest Rate, Effective Percentage
5.70% 1
5.70% 1
Metcalf [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 2
251 2
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1 2
6.90% 1 2
Pasadena [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
185 3
208 3
Debt Instrument, Interest Rate, Effective Percentage
8.80% 1 3
8.60% 1 3
Bethpage [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
98 4
103 4
Debt Instrument, Interest Rate, Effective Percentage
7.00% 1 4
7.00% 1 4
Deer Park [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 
99 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
7.70% 1
Gilroy note payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
49 
64 
Debt Instrument, Interest Rate, Effective Percentage
10.60% 1
10.60% 1
Gilroy Energy Center [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 
38 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
7.30% 1
Whitby [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 5
26 5
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1 5
9.10% 1 5
GEC Holdings [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 
14 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
16.60% 1
Russell City Energy [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
244 
0 
Debt Instrument, Interest Rate, Effective Percentage
4.10% 1
0.00% 1
Los Esteros Project [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
83 
0 
Debt Instrument, Interest Rate, Effective Percentage
3.80% 1
0.00% 1
Other [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
8 
13 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
0.00% 1
Project Financing Total [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 1,691 
$ 1,922 
Debt (Details 4) (USD $)
Dec. 31, 2011
Dec. 31, 2010
Schedule of Future Minimum Lease Payments for Capital Leases [Line Items]
 
 
Power generation capacity
11,391 
13,656 
Maximum Remaining Lease Term
37 
 
Minimum Lease Payments, Sale Leaseback Transactions [Abstract]
 
 
Minimum Lease Payments, Sale Leaseback Transactions, within One Year
$ 41,000,000 1
 
Minimum Lease Payments, Sale Leaseback Transactions, within Two Years
38,000,000 1
 
Minimum Lease Payments, Sale Leaseback Transactions, within Three Years
26,000,000 1
 
Minimum Lease Payments, Sale Leaseback Transactions, within Four Years
25,000,000 1
 
Minimum Lease Payments, Sale Leaseback Transactions, within Five Years
25,000,000 1
 
Minimum Lease Payments, Sale Leaseback Transactions, Thereafter
143,000,000 1
 
Minimum Lease Payments, Sale Leaseback Transactions
298,000,000 1
 
Interest Portion of Minimum Lease Payments, Sale Leaseback Transactions
110,000,000 1
 
Present Value of Future Minimum Lease Payments, Sale Leaseback Transactions
188,000,000 1
 
Capital Leases, Future Minimum Payments Due [Abstract]
 
 
Capital Leases, Future Minimum Payments Due, Current
40,000,000 
 
Capital Leases, Future Minimum Payments Due in Two Years
38,000,000 
 
Capital Leases, Future Minimum Payments Due in Three Years
39,000,000 
 
Capital Leases, Future Minimum Payments Due in Four Years
37,000,000 
 
Capital Leases, Future Minimum Payments Due in Five Years
40,000,000 
 
Capital Leases, Future Minimum Payments Due Thereafter
200,000,000 
 
Capital Leases, Future Minimum Payments Due
394,000,000 
 
Capital Leases, Future Minimum Payments, Interest Included in Payments
170,000,000 
 
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments
224,000,000 
 
Total Leases Future Minimum Payments [Abstract]
 
 
Total Leases, Future Minimum Payments Due, Current
81,000,000 
 
Total Leases, Future Minimum Payments Due in Two Years
76,000,000 
 
Total Leases, Future Minimum Payments Due in Three Years
65,000,000 
 
Total Leases, Future Minimum Payments Due in Four Years
62,000,000 
 
Total Leases, Future Minimum Payments Due in Five Years
65,000,000 
 
Total Leases, Future Minimum Payments Due Thereafter
343,000,000 
 
Total Leases, Future Minimum Payments Due
692,000,000 
 
Total Leases, Future Minimum Payments, Interest Included in Payments
280,000,000 
 
Total Leases, Future Minimum Payments, Present Value of Net Minimum Payments
412,000,000 
 
Lease Assets, Historical Cost
1,000,000,000 
1,000,000,000 
Lease Assets, Accumulated Depreciation
$ 340,000,000 
$ 312,000,000 
Debt (Details 5) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2011
One Month [Member]
Dec. 31, 2011
Two Months [Member]
Dec. 31, 2011
Three Months [Member]
Dec. 31, 2011
Six Months [Member]
Dec. 31, 2011
Nine Months [Member]
Dec. 31, 2011
Twelve Months [Member]
Dec. 31, 2011
Minimum [Member]
Dec. 31, 2011
Maximum [Member]
Dec. 31, 2011
Corporate Revolving Facility [Member]
Dec. 31, 2010
Corporate Revolving Facility [Member]
Dec. 31, 2011
CDH [Member]
Dec. 31, 2010
CDH [Member]
Dec. 31, 2011
NDH Project Debt Credit Facility [Member]
Dec. 31, 2010
NDH Project Debt Credit Facility [Member]
Dec. 31, 2011
Various Project Financing Facilities [Member]
Dec. 31, 2010
Various Project Financing Facilities [Member]
Line of Credit Facility [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Fair Value of Amount Outstanding
$ 763 
$ 711 
 
 
 
 
 
 
 
 
$ 440 1
$ 443 1
$ 193 2
$ 165 2
$ 0 3
$ 34 3
$ 130 
$ 69 
Corporate Revolving Facility Interest Details [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Applicable margin range percentage above base rate
 
 
 
 
 
 
 
 
2.00% 
2.25% 
 
 
 
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
 
1 
2 
3 
6 
9 
12 
 
 
 
 
 
 
 
 
 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
 
 
 
 
 
 
 
 
3.00% 
3.25% 
 
 
 
 
 
 
 
 
Unused commitment fee range percentage
 
 
 
 
 
 
 
 
0.50% 
0.75% 
 
 
 
 
 
 
 
 
Debt (Details 6) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Portion at Fair Value, Fair Value Disclosure [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
$ 6,219 
$ 4,695 
Notes Payable, Other Payables, Disclosure
1,467 1
1,673 1
Loans Payable, Fair Value Disclosure
1,615 
0 
Project Debt Disclosure
0 
1,303 
Lines of Credit, Fair Value Disclosure
0 
1,182 
Subsidiaries Notes Disclosure
1,070 
1,067 
Debt Excluding Capital Leases
10,371 
9,920 
Carrying (Reported) Amount, Fair Value Disclosure [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
5,892 
4,691 
Notes Payable, Other Payables, Disclosure
1,504 1
1,708 1
Loans Payable, Fair Value Disclosure
1,646 
0 
Project Debt Disclosure
0 
1,258 
Lines of Credit, Fair Value Disclosure
0 
1,184 
Subsidiaries Notes Disclosure
972 
965 
Debt Excluding Capital Leases
$ 10,014 
$ 9,806 
Debt (Textuals 1) (Details) (USD $)
6 Months Ended 12 Months Ended
Jun. 30, 2011
Dec. 31, 2011
Dec. 31, 2010
Sep. 1, 2011
Dec. 31, 2009
Debt Instrument [Line Items]
 
 
 
 
 
Number of power plants
 
 
 
 
6 
Power generation capacity
 
11,391 
13,656 
 
 
Payments of Debt Issuance Costs
 
$ 22,000,000 
 
 
 
Write off of Deferred Debt Issuance Cost
 
 
19,000,000 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Early Repayment of Senior Debt
 
1,200,000,000 
3,500,000,000 
 
 
Repayment of Project Debt
 
 
 
340,000,000 
 
Term loan interest rate spread option Federal Funds effective rate
 
0.50% 
 
 
 
Term loan interest rate spread option Prime Rate
 
2.25% 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
 
3.25% 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum
 
1.25% 
 
 
 
Percentage of principal amount of Term Loan to be paid quarterly
 
0.25% 
 
 
 
Repricing transaction premium percentage
 
1.00% 
 
 
 
Days allowed to make offer to prepay
 
30 
 
 
 
Percentage of Term Loan amounts held by lenders
 
50.00% 
 
 
 
Deferred Finance Costs, Gross
 
14,000,000 
 
 
 
Term Loan debt extinguishment costs
74,000,000 
5,000,000 
 
 
 
Write-off amount of unamortized deferred financing costs
36,000,000 
 
 
 
 
Write-off amount of debt discount
25,000,000 
 
 
 
 
Subsidiary Project Debt prepayment premiums
13,000,000 
 
 
 
 
Back-Stopped Letters of Credit
 
83,000,000 
 
 
 
Percentage added to Federal Funds Effective Rate to arrive at base rate
 
0.50% 
 
 
 
Repayment time for drawings under letters of credit
 
2 
 
 
 
Line of Credit Facility, Maximum Borrowing Capacity
 
1,000,000,000 
 
 
 
Equity Method Investment, Ownership Percentage
 
50.00% 
 
 
 
Excess amount of asset sales requiring mandatory prepayments
 
3,000,000,000 
 
 
 
CDHI Letter of Credit Facility Total
 
200,000,000 
 
 
 
CDHI Upsize Facility Total
 
$ 300,000,000 
 
 
 
Debt, Weighted Average Interest Rate
 
8.90% 
8.90% 
 
 
Minimum [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Applicable margin range percentage above base rate
 
2.00% 
 
 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
 
3.00% 
 
 
 
Unused commitment fee range percentage
 
0.50% 
 
 
 
Maximum [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Applicable margin range percentage above base rate
 
2.25% 
 
 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
 
3.25% 
 
 
 
Unused commitment fee range percentage
 
0.75% 
 
 
 
One Month [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
1 
 
 
 
Two Months [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
2 
 
 
 
Three Months [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
3 
 
 
 
Six Months [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
6 
 
 
 
Nine Months [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
9 
 
 
 
Twelve Months [Member]
 
 
 
 
 
Debt Disclosure [Abstract]
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
12 
 
 
 
Debt (Textuals 2) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Debt Instrument [Line Items]
 
 
 
Deferred Finance Costs, Gross
$ 14 
 
 
Power generation capacity
11,391 
13,656 
 
Letters of credit issued
581 1
588 1
 
Long-term Debt
10,425 
10,256 
 
Debt extinguishment costs
(94)
(91)
(76)
Loans Payable, New [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
360 
 
 
Deferred Finance Costs, Gross
5 
 
 
Russell City Project [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
845 
 
 
Deferred Finance Costs, Gross
27 
 
 
Power generation capacity
619 
 
 
Construction Loan Facility
700 
 
 
Project Letter of Credit Facility
77 
 
 
Debt Service Letter of Credit Facility
68 
 
 
Term Loan Period
10 
 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
2.25% 
 
 
Amount Drawn Under Construction Loan
244 
 
 
Letters of credit issued
61 
 
 
Los Esteros Project [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
373 
 
 
Deferred Finance Costs, Gross
12 
 
 
Construction Loan Facility
305 
 
 
Project Letter of Credit Facility
38 
 
 
Debt Service Letter of Credit Facility
30 
 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
2.25% 
 
 
Amount Drawn Under Construction Loan
83 
 
 
Letters of credit issued
30 
 
 
Notes Payable to Banks [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Long-term Debt
 
1,258 2
 
CCFC Notes [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
 
 
1,000 
Deferred Finance Costs, Gross
 
 
21 
Debt Instrument, Interest Rate, Stated Percentage
 
 
8.00% 
Debt extinguishment costs
 
 
$ 49 
Los Esteros Project [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Power generation capacity
188 
 
 
Power generation capacity after upgrade
308 
 
 
Assets and Liabilities with Recurring Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Transfers into level 3
$ (2)1 2
$ 0 1 2
$ 0 1 2
Cash equivalents
1,415 3
1,297 3
 
Margin deposits
140 4
162 4
 
Commodity futures contracts
1,043 
550 
 
Commodity forward contracts
111 5
341 5
 
Interest rate swaps
10 
4 
 
Total assets
2,719 
2,354 
 
Margin deposits held by us posted by our counterparties
34 4 6
6 4 6
 
Commodity futures contracts
899 
574 
 
Commodity forward contracts
204 5
143 5
 
Interest rate swaps
320 
371 
 
Total liabilities
1,457 
1,094 
 
Transfers out of level 3
0 2 7
3 2 7
(34)2 7
Fair Value, Inputs, Level 1 [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Cash equivalents
1,415 3
1,297 3
 
Margin deposits
140 
162 
 
Commodity futures contracts
1,043 
550 
 
Commodity forward contracts
0 5
0 5
 
Interest rate swaps
0 
0 
 
Total assets
2,598 
2,009 
 
Margin deposits held by us posted by our counterparties
34 
6 
 
Commodity futures contracts
899 
574 
 
Commodity forward contracts
0 5
0 5
 
Interest rate swaps
0 
0 
 
Total liabilities
933 
580 
 
Fair Value, Inputs, Level 2 [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Cash equivalents
0 3
0 3
 
Margin deposits
0 
0 
 
Commodity futures contracts
0 
0 
 
Commodity forward contracts
74 5
287 5
 
Interest rate swaps
10 
4 
 
Total assets
84 
291 
 
Margin deposits held by us posted by our counterparties
0 
0 
 
Commodity futures contracts
0 
0 
 
Commodity forward contracts
184 5
119 5
 
Interest rate swaps
320 
371 
 
Total liabilities
504 
490 
 
Fair Value, Inputs, Level 3 [Member]
 
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
Cash equivalents
0 3
0 3
 
Margin deposits
0 
0 
 
Commodity futures contracts
0 
0 
 
Commodity forward contracts
37 5
54 5
 
Interest rate swaps
0 
0 
 
Total assets
37 
54 
 
Margin deposits held by us posted by our counterparties
0 
0 
 
Commodity futures contracts
0 
0 
 
Commodity forward contracts
20 5
24 5
 
Interest rate swaps
0 
0 
 
Total liabilities
$ 20 
$ 24 
 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
Balance, beginning of period
$ 30 
$ 38 
$ 105 
Included in net income:
 
 
 
Included in operating revenues
5 1
7 1
14 1
Included in fuel and purchased energy expense
0 2
0 2
5 2
Included in OCI
2 
2 
(4)
Purchases, issuances and settlements:
 
 
 
Settlements
(18)
(20)
(48)
Transfers into level 3
(2)3 4
0 3 4
0 3 4
Transfers out of level 3
0 4 5
3 4 5
(34)4 5
Balance, end of period
17 
30 
38 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Change in Unrealized Gain (Loss) Held At Period End
5 2
7 2
19 2
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure
1,249 
1,094 
 
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure
$ 166 
$ 203 
 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Price Risk Derivatives [Abstract]
 
 
Power (MWh)
(21)
(50)
Natural gas (MMBtu)
(200)
31 
Interest rate swaps
$ 5,639 1
$ 6,171 1
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
$ 1,051 
$ 725 
Long-term derivative assets
113 
170 
Total derivative assets
1,164 
895 
Current derivative liabilities
1,144 
718 
Long-term derivative liabilities
279 
370 
Total derivative liabilities
1,423 
1,088 
Net derivative assets (liabilities)
(259)
(193)
Fair Value of Derivative Assets
1,164 
895 
Fair Value of Derivative Liabilities
1,423 
1,088 
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
61 
163 
Fair Value of Derivative Liabilities
167 
195 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
1,103 
732 
Fair Value of Derivative Liabilities
1,256 
893 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
0 
0 
Long-term derivative assets
10 
4 
Total derivative assets
10 
4 
Current derivative liabilities
166 
197 
Long-term derivative liabilities
154 
174 
Total derivative liabilities
320 
371 
Net derivative assets (liabilities)
(310)
(367)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
10 
2 
Fair Value of Derivative Liabilities
149 
143 
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
0 
2 
Fair Value of Derivative Liabilities
171 
228 
Commodity Option [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
1,051 
725 
Long-term derivative assets
103 
166 
Total derivative assets
1,154 
891 
Current derivative liabilities
978 
521 
Long-term derivative liabilities
125 
196 
Total derivative liabilities
1,103 
717 
Net derivative assets (liabilities)
51 
174 
Commodity Option [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
51 
161 
Fair Value of Derivative Liabilities
18 
52 
Commodity Option [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
1,103 
730 
Fair Value of Derivative Liabilities
$ 1,085 
$ 665 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Realized gain (loss) on derivatives
$ (50)
$ 83 
$ 5 
Unrealized gain (loss)
30 1
(56)1
87 1
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
Power contracts included in operating revenues
(20)
(19)
7 
Natural gas contracts included in fuel and purchased energy expense
138 
276 
109 
Interest rate swaps included in interest expense
7 
(7)
(24)
Gain (Loss) on interest rate derivatives, net
145 
223 
0 
Gain (Loss) on Derivative Instruments, Net, Pretax
(20)1
27 1
92 1
Interest Rate Swap [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Realized gain (loss) on derivatives
(193)
(31)
(32)
Unrealized gain (loss)
55 1
(199)1
8 1
Commodity Option [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Realized gain (loss) on derivatives
143 
114 
37 
Unrealized gain (loss)
$ (25)1
$ 143 1
$ 79 1
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
$ (94)
$ 166 
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
25 1
(141)1
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
(3)
0 
Interest Rate Swap [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
(23)
193 
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
(138)1 2
(389)1 3
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
(1)
0 
Commodity Option [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
(71)
(27)
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
163 1 4
248 1 4
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
$ (2)
$ 0 
Derivative Instruments (Textuals) (Details) (USD $)
3 Months Ended 12 Months Ended
Sep. 30, 2011
Jun. 30, 2011
Dec. 31, 2011
Dec. 31, 2010
Derivative Instruments (Textuals) [Abstract]
 
 
 
 
Maximum Length of Power Purchase Agreements
 
 
23 
 
Maximum length of time hedging using commodity derivative instruments
 
 
1 
 
Maximum length of time hedging using interest rate derivative instruments
 
 
12 
 
Derivative, Net Liability Position, Aggregate Fair Value
 
 
$ 138,000,000 
 
Collateral Already Posted, Aggregate Fair Value
 
 
90,000,000 
 
Additional Collateral, Aggregate Fair Value
 
 
2,000,000 
 
Early Repayment of Senior Debt
 
 
1,200,000,000 
3,500,000,000 
Notional Amount Interest Rate Derivative Underlying Debt Repaid During Period
 
 
1,000,000,000 
 
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net
 
 
91,000,000 
206,000,000 
Unrealized losses associated with interest rate swap breakage costs
 
17,000,000 
32,000,000 
183,000,000 
Cumulative cash flow hedge losses remaining in AOCI
 
 
172,000,000 
122,000,000 
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months
 
 
15,000,000 
 
Losses from interest rate contracts reclassified from OCI into earnings
15,000,000 
 
 
 
Notional Amount Interest Rate Derivative Underlying Debt Repaid
 
 
4,100,000,000 
3,300,000,000 
Losses from reclassification of interest rate contracts due to settlement
 
$ 17,000,000 
 
 
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Use of Collateral [Abstract]
 
 
Margin deposits
$ 140 1
$ 162 1
Natural gas and power prepayments
42 
43 
Total margin deposits and natural gas and power prepayments with our counterparties
182 2
205 2
Letters of credit issued
581 3
588 3
First priority liens under power and natural gas agreements
1 4
0 4
First priority liens under interest rate swap agreements
318 
391 
Total letters of credit and first priority liens with our counterparties
900 
979 
Margin deposits held by us posted by our counterparties
34 1 5
6 1 5
Letters of credit posted with us by our counterparties
0 
66 
Total margin deposits and letters of credit posted with us by our counterparties
34 
72 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
20 
22 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
162 
183 
Back-stopped amount of letters of credit used for commodity procurement and risk management activities
 
63 
Commodity Instruments Collateralized By First Priority Liens, Fair Value
 
$ 193 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Income Tax Disclosure [Abstract]
 
 
 
U.S.
$ (232)
$ (226)
$ 116 
International
20 
(4)
13 
Total
$ (212)
$ (230)
$ 129 
Income Taxes (Components of Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Current:
 
 
 
Federal
$ (16)
$ (1)
$ (2)
State
12 
10 
(2)
Foreign
3 
3 
3 
Total current
(1)
12 
(1)
Deferred:
 
 
 
Federal
(33)
(70)
13 
State
9 
0 
4 
Foreign
3 
(10)
(1)
Total deferred
(21)
(80)
16 
Total income tax expense (benefit)
$ (22)
$ (68)1
$ 15 
Income Taxes (Effective Income Tax Expense (Benefit) Rate) (Details)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Income Tax [Line Items]
 
 
 
Federal statutory tax expense (benefit) rate
(35.00%)
(35.00%)
35.00% 
State tax expense (benefit), net of federal benefit
6.50% 
2.80% 
1.00% 
Depletion in excess of basis
0.00% 
(1.30%)
0.00% 
Valuation allowances
56.70% 
33.60% 
(139.20%)
Effective Income Tax Rate Reconciliation Change In Deferred Tax Assets Valuation Allowance Due To Reconsolidation
(36.00%)
0.00% 
0.00% 
Foreign taxes
(0.90%)
9.90% 
(9.20%)
Non-deductible reorganization items
0.50% 
0.30% 
1.30% 
Income from cancellation of indebtedness
0.00% 
0.00% 
69.00% 
Intraperiod allocation
19.90% 
(40.10%)
45.40% 
Bankruptcy settlement
(15.70%)
0.00% 
0.00% 
Change in unrecognized tax benefits
(6.60%)
0.60% 
1.40% 
Permanent differences and other items
0.20% 
(0.40%)
6.90% 
Effective income tax expense (benefit) rate
(10.40%)
(29.60%)
11.60% 
Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Dec. 31, 2010
Deferred tax assets:
 
 
NOL and credit carryforwards
$ 3,290 
$ 3,138 
Taxes related to risk management activities and derivatives
58 
18 
Reorganization items and impairments
318 
422 
Foreign capital losses
24 
25 
Other differences
26 
12 
Deferred tax assets before valuation allowance
3,716 
3,615 
Valuation allowance
(2,336)
(2,386)
Total deferred tax assets
1,380 
1,229 
Deferred tax liabilities: property, plant and equipment
(1,364)
(1,280)
Net deferred tax asset (liability)
16 
(51)
Less: Current portion deferred tax asset (liability)
(2)
(4)
Less: Non-current deferred tax asset
18 
30 
Deferred income tax liability, net of current
$ 0 
$ (77)
Income Taxes (Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Income Tax Disclosure [Abstract]
 
 
 
Deferred income tax liability, net of current
$ 42 
$ (86)
$ 43 
Intraperiod tax allocation expense (benefit) included in discountinued operations
0 
59 
0 
Intraperiod tax allocation expense (benefit) included in OCI
$ (45)
$ 27 
$ (43)
Income Taxes (Income Tax Contingencies) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Income Tax Disclosure [Abstract]
 
 
 
Balance, beginning of period
$ (88)
$ (98)
$ (90)
Increases related to prior year tax positions
0 
(1)
(11)
Decreases related to prior year tax positions
1 
11 
2 
Settlements
0 
0 
1 
Decrease related to lapse of statute of limitations
13 
0 
0 
Balance, end of period
$ (74)
$ (88)
$ (98)
Income Taxes (Textuals) (Details) (USD $)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Dec. 31, 2008
Intraperiod income tax [Line Items]
 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, Domestic
$ 7,900,000,000 
 
 
 
Income Tax Expense (Benefit) [Abstract]
 
 
 
 
Deferred income tax liability, net of current
42,000,000 
(86,000,000)
43,000,000 
 
Federal statutory tax expense (benefit) rate
(35.00%)
(35.00%)
35.00% 
 
Income Tax Disclosure (Textuals) [Abstract]
 
 
 
 
One time tax benefit from consolidation
76,000,000 
 
 
 
Unrecognized Tax Benefits
74,000,000 
88,000,000 
98,000,000 
90,000,000 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
28,000,000 
 
 
 
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward
46,000,000 
 
 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
20,000,000 
 
 
 
Cancellation of Debt Income Related to Stock Distribution
66,000,000 
 
 
 
Cancellation of Debt Income Related to Stock Distribution for State Income Tax Purposes
39,000,000 
 
 
 
Operating Loss Carryforwards
7,900,000,000 
 
 
 
Operating Loss Carryforwards Available To Offset Future Income
6,300,000,000 
 
 
 
Operating Loss Carryforwards Not Limited On Use
2,400,000,000 
 
 
 
NOLs expected to expire unutilized
640,000,000 
 
 
 
Percent Decline In Market Cap Required To Trigger Transfer Restrictions
35.00% 
 
 
 
Holders with ownership that could be affected by transfer restrictions
5.00% 
 
 
 
Reduction In State NOLs
44,000,000 
 
 
 
Reduction Of State Taxable Income
24,000,000 
 
 
 
Valuation allowance
2,336,000,000 
2,386,000,000 
 
 
Valuation Allowance, Deferred Tax Asset, Change in Amount
(50,000,000)
(186,000,000)
(113,000,000)
 
Emergence Date Capitalization
8,600,000,000 
 
 
 
Percent Change in Ownership Required To Trigger Transfer Restrictions
25.00% 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, State and Local
4,200,000,000 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, Foreign
1,000,000,000 
 
 
 
Intraperiod tax expense from a prior period [Member]
 
 
 
 
Income Tax Expense (Benefit) [Abstract]
 
 
 
 
Deferred income tax liability, net of current
 
$ 13,000,000 
 
 
Earnings (Loss) per Share (Details)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Earnings (Loss) per Share [Abstract]
 
 
 
Shares Of New, Reorganized Common Stock
485,000,000 
 
 
Diluted weighted average shares calculation:
 
 
 
Weighted average shares outstanding (basic)
485,381,000 
486,044,000 
485,659,000 
Share-based awards
0 
1,250,000 
660,000 
Weighted average shares outstanding (diluted)
485,381,000 
487,294,000 
486,319,000 
Items excluded from diluted earnings (loss) per common share
 
 
 
Share-based awards
15,260,000 
14,883,000 
13,158,000 
Stock-Based Compensation (Details) (USD $)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
$ 7,000,000 
$ 4,000,000 
$ 8,000,000 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
 
 
 
Options Outstanding, Beginning balance, Number
17,164,890 
 
 
Options Outstanding, Beginning balance, Weighted Average Exercise Price
$ 17.44 
 
 
Options Ouststanding, Beginning balance, Weighted Average Remaining Term (in years)
5.6 
 
 
Options Outstanding, Beginning balance, Aggregate Intrinsic Value (in $ millions)
8,000,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross
953,467 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price
$ 14.27 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period
7,554 
 
0 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price
$ 11.66 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period
197,316 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price
$ 13.04 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period
247,585 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price
$ 17.56 
 
 
Options Outstanding, Ending balance, Number
17,665,902 
17,164,890 
 
Options Outstanding, Ending balance, Weighted Average Exercise Price
$ 17.32 
$ 17.44 
 
Options Ouststanding, Ending balance, Weighted Average Remaining Term (in years)
4.8 
5.6 
 
Options Outstanding, Ending balance, Aggregate Intrinsic Value (in $ millions)
26,000,000 
8,000,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number
8,297,284 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price
$ 19.49 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term
4.6 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value
2,000,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number
17,377,738 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price
$ 17.39 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term
4.7 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value
25,000,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term
6.5 1
6.5 1
6.5 1
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate
0.00% 2
0.00% 2
0.00% 2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 5.49 
$ 1.98 
$ 5.67 
Restricted Stock and Stock Unit Activity [Abstract]
 
 
 
Nonvested Restricted Stock, Beginning balance, Number
2,683,117 
 
 
Nonvested Restricted Stock, Beginning balance, Weighted Average Grant Date Fair Value
$ 11.16 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
1,636,026 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 14.37 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
322,034 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period, Weighted Average Grant Date Fair Value
$ 12.32 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
486,751 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 14.41 
 
 
Nonvested Restricted Stock, Ending balance, Number
3,510,358 
2,683,117 
 
Nonvested Restricted Stock, Ending balance, Weighted Average Grant Date Fair Value
$ 12.10 
$ 11.16 
 
Disclosure of Compensation Related Costs Share-based Payments (Textuals) [Abstract]
 
 
 
Vesting period for graded and cliff vesting options - minimum
1 
 
 
Vesting period for graded and cliff vesting options - maximum
5 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Minimum Range
5 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Maximum Range
10 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Directors
567,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Employees
27,533,000 
 
 
Vest Term of First Sub Grant
1 
 
 
Vest Term of the Second Sub-Grant
2 
 
 
Percentage of sub-grants representing the total
33.33% 
 
 
Vest Term of the Third Sub-Grant
3 
 
 
Grants in Option Grants with Three Year Cliff Vesting
1 
 
 
Vesting term of option grants with three year cliff vesting
3 
 
 
Allocated Share-based Compensation Expense
24,000,000 
24,000,000 
38,000,000 
Minimum [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term
 
4.0 1
6.0 1
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
1.70% 3
1.30% 3
2.30% 3
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
31.20% 4
31.40% 4
52.10% 4
Maximum [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
3.20% 3
3.30% 3
2.90% 3
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
44.90% 4
37.60% 4
73.00% 4
Stock Options [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
12,000,000 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
1.3 
 
 
Restricted Stock [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
16,000,000 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
1.3 
 
 
Restricted Stock Units (RSUs) [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
$ 0.0 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
0.4 
 
 
Defined Contribution and Defined Benefit Plans (Details) (USD $)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Defined Contribution and Defined Benefit Plans [Abstract]
 
 
 
Defined Contribution Plan, Cost Recognized
$ 10,000,000 
$ 9,000,000 
$ 9,000,000 
Employer Matching Contribution Percentage
100.00% 
 
 
Deferral Election Percentage For Employer Matching Contribution
5.00% 
 
 
Employee Deferral Limit Percentage
75.00% 
 
 
Pension and Other Postretirement Defined Benefit Plans, Liabilities From Acquisition
 
6,000,000 
 
Grandfathered Pension Liability Employees
 
130 
 
Defined Benefit Plan, Assets for Plan Benefits
10,000,000 
8,000,000 
 
Pension and Other Postretirement Defined Benefit Plans, Liabilities
18,000,000 
15,000,000 
 
Defined Benefit Plan, Amounts Recognized in Balance Sheet
8,000,000 
7,000,000 
 
Defined Benefit Plan, Net Periodic Benefit Cost
1,000,000 
9,000,000 
 
Defined Benefit Plan, Net Periodic Benefit Cost Related To Voluntary Retirement Incentive
8,000,000 
 
 
Number Of Employees That Accepted The Voluntray Retirement Incentive
31 
 
 
Number Of Employees Eligible For The Voluntray Retirement Incentive
48 
 
 
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax
3,000,000 
0 
 
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year
3,000,000 
8,000,000 
 
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year
2,000,000 
 
 
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter
$ 1,000,000 
 
 
Capital Structure (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 13 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Feb. 9, 2012
Feb. 7, 2012
Class of Stock [Line Items]
 
 
 
 
 
Shares Of New, Reorganized Common Stock
485,000,000 
 
 
 
 
Common Stock, Shares Authorized
1,400,000,000 
1,400,000,000 
 
 
 
Common Stock, Shares, Issued
490,468,815 
444,883,356 
 
 
 
Common Stock, Par or Stated Value Per Share
$ 0.001 
$ 0.001 
 
 
 
Common Stock, Shares, Outstanding
481,743,738 
444,435,198 
 
 
481,743,738 
Treasury Stock, Shares
8,725,077 
448,158 
 
 
 
Treasury Stock, Value
$ 125 
$ 5 
 
 
 
Stock Repurchase Program, Authorized Amount
300 
 
 
 
 
Treasury Stock, Value, Acquired, Cost Method
$ 120 
$ 2 
$ 2 
$ 124 
 
Treasury Stock Acquired, Average Cost Per Share
$ 14.60 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
Total common shares outstanding, beginning balance
488,693,630 
487,745,299 
486,874,489 
488,693,630 
 
Resolution of claims/inter-creditor disputes
0 
0 
0 
 
 
Shares issued under Calpine Equity Incentive Plans
1,187,181 
948,331 
870,810 
 
 
Share repurchase program
8,137,073 
 
 
8,524,576 
 
Total common shares outstanding, ending balance
481,743,738 
488,693,630 
487,745,299 
 
 
Shares Issued [Member]
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
Total common shares outstanding, beginning balance
444,883,356 
443,325,827 
429,025,057 
444,883,356 
 
Resolution of claims/inter-creditor disputes
44,258,432 
488,612 
13,167,420 
 
 
Shares issued under Calpine Equity Incentive Plans
1,327,027 
1,068,917 
1,133,350 
 
 
Share repurchase program
0 
 
 
 
 
Total common shares outstanding, ending balance
490,468,815 
444,883,356 
443,325,827 
 
 
Shares Held inTreasury [Member]
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
Total common shares outstanding, beginning balance
448,158 
327,572 
65,032 
448,158 
 
Resolution of claims/inter-creditor disputes
0 
0 
0 
 
 
Shares issued under Calpine Equity Incentive Plans
139,846 
120,586 
262,540 
 
 
Share repurchase program
8,137,073 
 
 
 
 
Total common shares outstanding, ending balance
8,725,077 
448,158 
327,572 
 
 
Shares Held in Reserve [Member]
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
Total common shares outstanding, beginning balance
44,258,432 
44,747,044 
48,162,203 
44,258,432 
 
Resolution of claims/inter-creditor disputes
44,258,432 
488,612 
3,415,159 
 
 
Shares issued under Calpine Equity Incentive Plans
0 
0 
0 
 
 
Share repurchase program
0 
 
 
 
 
Total common shares outstanding, ending balance
0 
44,258,432 
44,747,044 
 
 
Inter-Creditor Disputes [Member]
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
Total common shares outstanding, beginning balance
0 
0 
9,752,261 
0 
 
Resolution of claims/inter-creditor disputes
0 
0 
9,752,261 
 
 
Shares issued under Calpine Equity Incentive Plans
0 
0 
0 
 
 
Share repurchase program
0 
 
 
 
 
Total common shares outstanding, ending balance
0 
0 
0 
 
 
Commitments and Contingencies (Narrative) (Details) (USD $)
Share data in Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Jul. 2, 2010
Commitments and Contingencies [Line Items]
 
 
 
 
Cash collateral outstanding related to bonds
4000000 
 
 
 
Outstanding claims related to guarantees
0 
 
 
 
Royalty Expense
$ 22,000,000 
$ 25,000,000 
$ 22,000,000 
 
Power generation capacity
11,391 
13,656 
 
 
Environmental remediation liabilities related to Acquisition
0 
 
 
10,000,000 
Amount of shares authorized to settle unsecured claims
485 
 
 
 
LTSA [Member]
 
 
 
 
Unrecorded Unconditional Purchase Obligation
 
 
 
 
Unrecorded Unconditional Purchase Obligation
70,000,000 
 
 
 
Term of Unrecorded Unconditional Purchase Obligation Lower Limit
1 
 
 
 
Term of Unrecorded Unconditional Purchase Obligation Upper Limit
7 
 
 
 
Public Utilities, Inventory, Fuel [Member]
 
 
 
 
Unrecorded Unconditional Purchase Obligation
 
 
 
 
Unrecorded Unconditional Purchase Obligation
$ 4,600,000,000 
 
 
 
Term of Unrecorded Unconditional Purchase Obligation Lower Limit
1 
 
 
 
Term of Unrecorded Unconditional Purchase Obligation Upper Limit
15 
 
 
 
Term of Unrecorded Unconditional Purchase Obligation Outlier
30 
 
 
 
Commitments and Contingencies (Schedules of Future Minimum Rental Payments) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Land and Other Operating Leases [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due, Current
$ 12 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
11 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
11 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
14 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
14 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
431 
 
 
Operating Leases, Future Minimum Payments Due
493 
 
 
Greenleaf [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
17 
 
 
KIAC [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due, Current
24 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
24 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
24 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
23 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
22 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
74 
 
 
Operating Leases, Future Minimum Payments Due
191 
 
 
Total Power Plant Leases [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due, Current
31 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
31 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
27 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
23 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
22 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
74 
 
 
Operating Leases, Future Minimum Payments Due
208 
 
 
Operating Leases, Rent Expense, Net
53 
60 
60 
Operting Lease Assets Total [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due, Current
43 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
42 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
38 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
37 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
36 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
505 
 
 
Operating Leases, Future Minimum Payments Due
701 
 
 
Office Equipment [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due, Current
13 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
12 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
10 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
10 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
9 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
32 
 
 
Operating Leases, Future Minimum Payments Due
86 
 
 
Operating Leases, Rent Expense, Net
13 
12 
12 
Greenleaf [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Guarantee Obligations Balance On First Anniversary
7 1
 
 
Guarantee Obligations Balance On Second Anniversary
7 1
 
 
Guarantee Obligations Balance On Third Anniversary
3 1
 
 
Guarantee Obligations Balance On Fourth Anniversary
0 1
 
 
Guarantee Obligations Balance On Fifth Anniversary
0 1
 
 
Guarantee Obligations Due After Five Years
$ 0 1
 
 
Commitments and Contingencies (Schedule of Guarantor Obligations) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2011
Guarantor Obligations [Line Items]
 
Guarantor Obligations, Maximum Exposure, Undiscounted
$ 17 1
Loans Payable [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
76 2
Guarantee Obligations Balance On Second Anniversary
73 2
Guarantee Obligations Balance On Third Anniversary
272 2
Guarantee Obligations Balance On Fourth Anniversary
36 2
Guarantee Obligations Balance On Fifth Anniversary
36 2
Guarantee Obligations Due After Five Years
236 2
Guarantor Obligations, Maximum Exposure, Undiscounted
729 2
Financial Standby Letter of Credit [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
669 1 3
Guarantee Obligations Balance On Second Anniversary
45 1 3
Guarantee Obligations Balance On Third Anniversary
0 1 3
Guarantee Obligations Balance On Fourth Anniversary
0 1 3
Guarantee Obligations Balance On Fifth Anniversary
0 1 3
Guarantee Obligations Due After Five Years
49 1 3
Guarantor Obligations, Maximum Exposure, Undiscounted
763 1 3
Surety Bonds [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
0 1 4 5
Guarantee Obligations Balance On Second Anniversary
0 1 4 5
Guarantee Obligations Balance On Third Anniversary
0 1 4 5
Guarantee Obligations Balance On Fourth Anniversary
0 1 4 5
Guarantee Obligations Balance On Fifth Anniversary
0 1 4 5
Guarantee Obligations Due After Five Years
4 1 4 5
Guarantor Obligations, Maximum Exposure, Undiscounted
4 1 4 5
Gurantee Obligations Total [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
752 
Guarantee Obligations Balance On Second Anniversary
125 
Guarantee Obligations Balance On Third Anniversary
275 
Guarantee Obligations Balance On Fourth Anniversary
36 
Guarantee Obligations Balance On Fifth Anniversary
36 
Guarantee Obligations Due After Five Years
289 
Guarantor Obligations, Maximum Exposure, Undiscounted
$ 1,513 
Segment and Significant Customer Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2010
Jun. 30, 2010
Mar. 31, 2010
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
$ 1,459 
$ 2,209 
$ 1,633 
$ 1,499 
$ 1,471 
$ 2,130 
$ 1,430 
$ 1,514 
$ 6,800 
$ 6,545 
$ 6,463 
Intersegment revenues
 
 
 
 
 
 
 
 
0 
0 
0 
Total operating revenues
 
 
 
 
 
 
 
 
6,800 
6,545 
6,463 
Commodity Margin
 
 
 
 
 
 
 
 
2,474 
2,391 
2,461 
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(33)1 2
171 1
100 1
Plant operating expense
 
 
 
 
 
 
 
 
904 
868 
868 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
550 
570 
456 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
131 
151 
174 
Other operating expenses
 
 
 
 
 
 
 
 
77 3
91 3
96 3
Impairment losses
 
 
 
 
 
 
 
 
 
116 
4 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
0 
(119)
0 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
(21)
(16)
(50)
Income from operations
196 
403 
183 
18 
89 
554 
108 
150 
800 
901 
1,013 
Interest expense, net of interest income
 
 
 
 
 
 
 
 
751 
802 
799 
Loss on interest rate derivatives
 
 
 
 
 
 
 
 
145 
223 
0 
Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
115 
106 
89 
Income (loss) before income taxes and discontinued operations
 
 
 
 
 
 
 
 
(211)
(230)
125 
Lease levelization
 
 
 
 
 
 
 
 
12 
 
 
Contract amortization
 
 
 
 
 
 
 
 
8 
 
 
RGGI compliance and other environmental costs
 
 
 
 
 
 
 
 
10 
9 
5 
West [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
2,372 
2,525 
3,311 
Intersegment revenues
 
 
 
 
 
 
 
 
12 
12 
28 
Total operating revenues
 
 
 
 
 
 
 
 
2,384 
2,537 
3,339 
Commodity Margin
 
 
 
 
 
 
 
 
1,061 
1,080 
1,245 
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
113 1 2
69 1
143 1
Plant operating expense
 
 
 
 
 
 
 
 
380 
351 
408 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
192 
207 
188 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
43 
55 
66 
Other operating expenses
 
 
 
 
 
 
 
 
41 3
59 3
73 3
Impairment losses
 
 
 
 
 
 
 
 
 
97 
4 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
0 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
(32)
Income from operations
 
 
 
 
 
 
 
 
518 
380 
681 
Texas [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
2,306 
2,162 
1,816 
Intersegment revenues
 
 
 
 
 
 
 
 
23 
22 
63 
Total operating revenues
 
 
 
 
 
 
 
 
2,329 
2,184 
1,879 
Commodity Margin
 
 
 
 
 
 
 
 
469 
504 
644 
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(102)1 2
89 1
(40)1
Plant operating expense
 
 
 
 
 
 
 
 
235 
285 
232 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
135 
150 
129 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
43 
38 
63 
Other operating expenses
 
 
 
 
 
 
 
 
3 3
2 3
14 3
Impairment losses
 
 
 
 
 
 
 
 
 
0 
0 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
(119)
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
0 
Income from operations
 
 
 
 
 
 
 
 
(49)
237 
166 
North [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
1,336 
978 
558 
Intersegment revenues
 
 
 
 
 
 
 
 
7 
6 
16 
Total operating revenues
 
 
 
 
 
 
 
 
1,343 
984 
574 
Commodity Margin
 
 
 
 
 
 
 
 
704 
535 
268 
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(13)1 2
21 1
46 1
Plant operating expense
 
 
 
 
 
 
 
 
177 
138 
91 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
138 
111 
67 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
24 
45 
18 
Other operating expenses
 
 
 
 
 
 
 
 
30 3
28 3
30 3
Impairment losses
 
 
 
 
 
 
 
 
 
0 
0 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
0 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
(21)
(16)
(18)
Income from operations
 
 
 
 
 
 
 
 
343 
250 
126 
Southeast [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
786 
880 
778 
Intersegment revenues
 
 
 
 
 
 
 
 
135 
138 
97 
Total operating revenues
 
 
 
 
 
 
 
 
921 
1,018 
875 
Commodity Margin
 
 
 
 
 
 
 
 
240 
272 
304 
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
1 1 2
22 1
(5)1
Plant operating expense
 
 
 
 
 
 
 
 
141 
123 
134 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
90 
109 
80 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
22 
12 
27 
Other operating expenses
 
 
 
 
 
 
 
 
5 3
4 3
11 3
Impairment losses
 
 
 
 
 
 
 
 
 
19 
0 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
0 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
0 
Income from operations
 
 
 
 
 
 
 
 
(17)
27 
47 
Consolidation and Elimination [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
0 
0 
0 
Intersegment revenues
 
 
 
 
 
 
 
 
(177)
(178)
(204)
Total operating revenues
 
 
 
 
 
 
 
 
(177)
(178)
(204)
Commodity Margin
 
 
 
 
 
 
 
 
0 
0 
0 
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(32)1 2
(30)1
(44)1
Plant operating expense
 
 
 
 
 
 
 
 
(29)
(29)
3 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
(5)
(7)
(8)
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
(1)
1 
0 
Other operating expenses
 
 
 
 
 
 
 
 
(2)3
(2)3
(32)3
Impairment losses
 
 
 
 
 
 
 
 
 
0 
0 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
0 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
0 
Income from operations
 
 
 
 
 
 
 
 
5 
7 
(7)
PJM Settlement, Inc. [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Major customer revenue
 
 
 
 
 
 
 
 
742 
 
 
Major customer receivables
 
 
 
 
 
 
 
 
$ 28 
 
 
Number of significant customers
 
 
 
 
 
 
 
 
1 
 
 
Quarterly Consolidated Financial Data (unaudited) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2010
Sep. 30, 2010
Jun. 30, 2010
Mar. 31, 2010
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Quarterly Financial Information Disclosure [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 1,459 
$ 2,209 
$ 1,633 
$ 1,499 
$ 1,471 
$ 2,130 
$ 1,430 
$ 1,514 
$ 6,800 
$ 6,545 
$ 6,463 
Income (loss) from operations
196 
403 
183 
18 
89 
554 
108 
150 
800 
901 
1,013 
Income (loss) before discontinued operations attributable to Calpine
(13)
190 
(70)
(297)
(186)
198 
(119)
(55)
(189)
(162)
110 
Discontinued operations, net of tax expense, attributable to Calpine
0 
0 
0 
0 
162 
19 
4 
8 
0 
193 
35 
Net income (loss) attributable to Calpine
$ (13)
$ 190 
$ (70)
$ (297)
$ (24)
$ 217 
$ (115)
$ (47)
$ (190)
$ 31 
$ 149 
Basic earnings (loss) per common share:
 
 
 
 
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$ (0.03)
$ 0.39 
$ (0.14)
$ (0.61)
$ (0.38)
$ 0.41 
$ (0.25)
$ (0.11)
$ (0.39)
$ (0.33)
$ 0.24 
Discontinued operations, net of tax expense, attributable to Calpine
$ 0.00 
$ 0.00 
$ 0.00 
$ 0.00 
$ 0.33 
$ 0.04 
$ 0.01 
$ 0.01 
$ 0.00 
$ 0.39 
$ 0.07 
Net income (loss) attributable to Calpine
$ (0.03)
$ 0.39 
$ (0.14)
$ (0.61)
$ (0.05)
$ 0.45 
$ (0.24)
$ (0.10)
$ (0.39)
$ 0.06 
$ 0.31 
Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
 
 
 
 
Income (loss) before discontinued operations attributable to Calpine
$ (0.03)
$ 0.39 
$ (0.14)
$ (0.61)
$ (0.38)
$ 0.41 
$ (0.25)
$ (0.11)
$ (0.39)
$ (0.33)
$ 0.24 
Discontinued operations, net of tax expense, attributable to Calpine
$ 0.00 
$ 0.00 
$ 0.00 
$ 0.00 
$ 0.33 
$ 0.04 
$ 0.01 
$ 0.01 
$ 0.00 
$ 0.39 
$ 0.07 
Discontinued operations, net of tax expense, attributable to Calpine
$ (0.03)
$ 0.39 
$ (0.14)
$ (0.61)
$ (0.05)
$ 0.45 
$ (0.24)
$ (0.10)
$ (0.39)
$ 0.06 
$ 0.31 
Schedule of Valuation and Qualifying Accounts Disclosure (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Allowance for Doubtful Accounts [Member]
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Balance at Beginning of Year
$ 2 
$ 14 
$ 42 
Charged to Expense
7 
(12)
2 
Deductions
0 1
0 1
(30)1
Charged to Other Accounts
4 
0 
0 
Balance at End of Year
13 
2 
14 
Deferred Tax Asset Valuation Allowance [Member]
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Balance at Beginning of Year
2,386 
2,572 
2,685 
Charged to Expense
(50)
(186)
(113)
Deductions
0 1
0 1
0 1
Charged to Other Accounts
0 
0 
0 
Balance at End of Year
$ 2,336 
$ 2,386 
$ 2,572