CALPINE CORP, 10-K filed on 2/13/2013
Annual Report
Document and Entity Information Cover (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Feb. 11, 2013
Jun. 30, 2012
Entity Information [Line Items]
 
 
 
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, 2012 
 
 
Document Fiscal Year Focus
2012 
 
 
Document Fiscal Period Focus
FY 
 
 
Amendment Flag
false 
 
 
Entity Common Stock, Shares Outstanding
 
456,236,512 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Public Float
 
 
$ 5,484 
Consolidated Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Operating revenues:
 
 
 
Commodity revenue
$ 5,417 
$ 6,753 
$ 6,578 
Unrealized mark-to-market gain (loss)
48 
35 
(61)
Other revenue
13 
12 
28 
Operating revenues
5,478 
6,800 
6,545 
Operating expenses:
 
 
 
Commodity expense
2,894 
4,299 
4,187 
Unrealized mark-to-market (gain) loss
130 
60 
(204)
Fuel and purchased energy expense
3,024 
4,359 
3,983 
Plant operating expense
922 
904 
868 
Depreciation and amortization expense
562 
550 
570 
Sales, general and other administrative expense
140 
131 
151 
Other operating expenses
78 
77 
91 
Total operating expenses
4,726 
6,021 
5,663 
Impairment losses
116 
(Gain) on sale of assets, net
(222)
(119)
(Income) from unconsolidated investments in power plants
(28)
(21)
(16)
Income from operations
1,002 
800 
901 
Interest expense
736 
760 
813 
Loss on interest rate derivatives
14 
145 
223 
Interest (income)
(11)
(9)
(11)
Debt extinguishment costs
30 
94 
91 
Other (income) expense, net
15 
21 
15 
Income (loss) before income taxes and discontinued operations
218 
(211)
(230)
Income tax expense (benefit)
19 
(22)1
(68)
Income (loss) before discontinued operations
199 
(189)
(162)
Discontinued operations, net of tax expense
193 
Net income (loss)
199 
(189)
31 
Net income attributable to the noncontrolling interest
(1)
Net income (loss) attributable to Calpine
$ 199 
$ (190)
$ 31 
Basic earnings (loss) per common share attributable to Calpine:
 
 
 
Weighted average shares of common stock outstanding (in shares)
467,752 
485,381 
486,044 
Income (loss) before discontinued operations attributable to Calpine (in dollars per share)
$ 0.43 
$ (0.39)
$ (0.33)
Discontinued operations, net of tax expense attributable to Calpine (in dollars per share)
$ 0.00 
$ 0.00 
$ 0.39 
Net income (loss) per common share attributable to Calpine — basic (in dollars per share)
$ 0.43 
$ (0.39)
$ 0.06 
Diluted earnings (loss) per common share attributable to Calpine:
 
 
 
Weighted average shares of common stock outstanding (in shares)
471,343 
485,381 
487,294 
Income (loss) before discontinued operations attributable to Calpine (in dollars per share)
$ 0.42 
$ (0.39)
$ (0.33)
Discontinued operations, net of tax expense attributable to Calpine (in dollars per share)
$ 0.00 
$ 0.00 
$ 0.39 
Net income (loss) per common share attributable to Calpine — diluted (in dollars per share)
$ 0.42 
$ (0.39)
$ 0.06 
Consolidated Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Net income (loss)
$ 199 
$ (189)
$ 31 
Cash flow hedging activities:
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
(61)
(69)
25 
Reclassification adjustment for (gain) loss on cash flow hedges realized in net income (loss)
(20)
(25)
141 
Unrealized actuarial losses arising during period
Foreign currency translation gain (loss)
(1)
Income tax (expense) benefit
45 
(27)
Other comprehensive income (loss)
(70)
(53)
141 
Comprehensive income (loss)
129 
(242)
172 
Comprehensive income attributable to the noncontrolling interest
(1)
Comprehensive income (loss) attributable to Calpine
$ 129 
$ (243)
$ 172 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Current assets:
 
 
Cash and cash equivalents ($109 and $285 attributable to VIEs)
$ 1,284 
$ 1,252 
Accounts receivable, net of allowance of $6 and $13
437 
598 
Margin deposits and other prepaid expense
244 
193 
Restricted cash, current ($53 and $57 attributable to VIEs)
193 
139 
Derivative assets, current
339 
1,051 
Inventory and other current assets
335 
329 
Total current assets
2,832 
3,562 
Property, plant and equipment, net ($4,192 and $4,313 attributable to VIEs)
13,005 
13,019 
Restricted cash, net of current portion ($59 and $53 attributable to VIEs)
60 
55 
Investments
81 
80 
Long-term derivative assets
98 
113 
Other assets
473 
542 
Total assets
16,549 
17,371 
Current liabilities:
 
 
Accounts payable
382 
435 
Accrued interest payable
180 
200 
Debt, current portion ($39 and $41 attributable to VIEs)
115 
104 
Derivative liabilities, current
357 
1,144 
Income taxes payable
11 
Other current liabilities
273 
276 
Total current liabilities
1,318 
2,162 
Debt, net of current portion ($2,660 and $2,522 attributable to VIEs)
10,635 
10,321 
Long-term derivative liabilities
293 
279 
Other long-term liabilities
247 
245 
Total liabilities
12,493 
13,007 
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, 2012 and 2011
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 492,495,100 shares issued and 457,048,970 shares outstanding at December 31, 2012, and 490,468,815 shares issued and 481,743,738 shares outstanding at December 31, 2011
Treasury stock, at cost, 35,446,130 and 8,725,077 shares, respectively
(594)
(125)
Additional paid-in capital
12,335 
12,305 
Accumulated deficit
(7,500)
(7,699)
Accumulated other comprehensive loss
(248)
(178)
Total Calpine stockholders’ equity
3,994 
4,304 
Noncontrolling interest
62 
60 
Total stockholders’ equity
4,056 
4,364 
Total liabilities and stockholders’ equity
$ 16,549 
$ 17,371 
Consolidated Balance Sheets Consolidated Balance Sheets Parentheticals (USD $)
Dec. 31, 2012
Dec. 31, 2011
Cash and cash equivalents attributable to VIE
$ 109,000,000 
$ 285,000,000 
Accounts Receivable, allowance for doubtful accounts
6,000,000 
13,000,000 
Restricted cash, current attributable to VIE
53,000,000 
57,000,000 
Property, plant and equipment, net attributable to VIE
4,192,000,000 
4,313,000,000 
Restricted cash, net of current portion attributable to VIE
59,000,000 
53,000,000 
Debt, current portion attributable to VIE
39,000,000 
41,000,000 
Debt, net of current portion attributable to VIE
$ 2,660,000,000 
$ 2,522,000,000 
Preferred Stock, par value (in dollars per share)
$ 0.001 
$ 0.001 
Preferred Stock, authorized shares (in shares)
100,000,000 
100,000,000 
Preferred Stock, issued shares (in shares)
Preferred Stock, outstanding shares (in shares)
Common Stock, par value (in dollars per share)
$ 0.001 
$ 0.001 
Common Stock, authorized shares (in shares)
1,400,000,000 
1,400,000,000 
Common Stock, issued shares (in shares)
492,495,100 
490,468,815 
Common Stock, outstanding shares (in shares)
457,048,970 
481,743,738 
Treasury Stock, shares (in shares)
35,446,130 
8,725,077 
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, 2009
$ 4,446 
$ 1 
$ (3)
$ 12,256 
$ (7,540)
$ (266)
$ (2)
Treasury stock transactions
(2)
(2)
Stock-based compensation expense
24 
24 
Other
29 
28 
Net income (loss)
31 
31 
Other comprehensive income (loss)
141 
141 
Balance at Dec. 31, 2010
4,669 
(5)
12,281 
(7,509)
(125)
26 
Treasury stock transactions
(120)
(120)
Stock-based compensation expense
24 
24 
Other
33 
33 
Net income (loss)
(189)
(190)
Other comprehensive income (loss)
(53)
(53)
Balance at Dec. 31, 2011
4,364 
(125)
12,305 
(7,699)
(178)
60 
Treasury stock transactions
(469)
(469)
Stock-based compensation expense
25 
25 
Option exercises
Other
Net income (loss)
199 
199 
Other comprehensive income (loss)
(70)
(70)
Balance at Dec. 31, 2012
$ 4,056 
$ 1 
$ (594)
$ 12,335 
$ (7,500)
$ (248)
$ 62 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Cash flows from operating activities:
 
 
 
Net income (loss)
$ 199 
$ (189)
$ 31 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense(1)
605 1
587 1
615 1
Debt extinguishment costs
82 
91 
Deferred income taxes
(21)
(26)
Impairment losses
116 
(Gain) loss on sale of power plants and other, net
(212)
13 
(314)
Unrealized mark-to-market (gain) loss
(72)2
(30)2
56 2
(Income) from unconsolidated investments in power plants
(28)
(21)
(16)
Return on unconsolidated investments in power plants
24 
11 
Stock-based compensation expense
25 
24 
24 
Change in operating assets and liabilities, net of effects of acquisitions:
Change in operating assets and liabilities, net of effects of acquisitions:
 
 
 
Accounts receivable
159 
74 
91 
Derivative instruments, net
(52)
15 
(52)
Other assets
(57)
277 
Accounts payable and accrued expenses
(86)
28 
(43)
Settlement of non-hedging interest rate swaps
156 
189 
69 
Other liabilities
(10)
11 
(2)
Net cash provided by operating activities
653 
775 
929 
Cash flows from investing activities:
 
 
 
Purchases of property, plant and equipment
(637)
(683)
(369)
Proceeds from sale of power plants, interests and other
825 
13 
954 
Purchase of Bosque Energy Center, Conectiv assets and BRSP, net of cash acquired
(432)
(1,680)
Cash acquired due to consolidation of OMEC
Return of investment from unconsolidated investments
Settlement of non-hedging interest rate swaps
(156)
(189)
(69)
(Increase) decrease in restricted cash
(59)
54 
322 
Purchases of deferred transmission credits
(12)
(31)
Other
(4)
Net cash used in investing activities
(470)
(836)
(831)
Cash flows from financing activities:
 
 
 
Borrowings under First Lien Term Loans
835 
1,657 
Repayments of First Lien Term Loans
(19)
Repayments on NDH Project Debt
(1,283)
Issuance of First Lien Notes
1,200 
3,491 
Repayments of First Lien Notes
(590)
Repayments on First Lien Credit Facility
(1,195)
(3,477)
Borrowings from project financing, notes payable and other
389 
327 
1,272 
Repayments of project financing, notes payable and other
(289)
(550)
(937)
Capital contributions from noncontrolling interest holder
33 
17 
Financing costs
(20)
(81)
(136)
Stock repurchases
(463)
(119)
Refund of financing costs
10 
Other
(3)
Net cash provided by (used in) financing activities
(151)
(14)
240 
Net increase (decrease) in cash and cash equivalents
32 
(75)
338 
Cash and cash equivalents, beginning of period
1,252 
1,327 
989 
Cash and cash equivalents, end of period
1,284 
1,252 
1,327 
Cash paid during the period for:
 
 
 
Interest, net of amounts capitalized
719 
656 
635 
Income taxes
16 
18 
21 
Supplemental disclosure of non-cash investing and financing activities:
 
 
 
Change in capital expenditures included in accounts payable
19 
(24)
Other non-cash additions to property, plant and equipment
13 
Liabilities assumed in BRSP acquisition
85 
Conversion of project debt to noncontrolling interest
$ 0 
$ 0 
$ 11 
Organization and Operations
Organization and Operations
Organization and Operations
We are a 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, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We engage in the purchase of natural gas and fuel oil as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to economically hedge our business risks and optimize our portfolio of power plants.
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.
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% partnership 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.
Change in Presentation — We have changed the presentation on our Consolidated Statements of Operations to separately present our Commodity revenue, unrealized mark-to-market gain (loss) and other revenue which are components of operating revenues and our Commodity expense and unrealized mark-to-market (gain) loss which are components of fuel and purchased energy expense. The change in presentation had no impact on our financial condition, results of operations or cash flows.
Reclassification — We have reclassified RGGI compliance and other environmental costs previously recorded in other operating expenses of $10 million and $9 million to Commodity expense on our Consolidated Statements of Operations for the years ended December 31, 2011 and 2010, respectively, to conform to the current year presentation.
Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. The following table summarizes our proportionate ownership interest in jointly-owned power plants:
As of December 31, 2012
 
Ownership Interest
 
Property, Plant & Equipment
 
Accumulated Depreciation
 
Construction in Progress
(in millions, except percentages)
Freestone Energy Center
 
75.0
%
 
$
392

 
$
(124
)
 
$
1

Hidalgo Energy Center
 
78.5
%
 
$
252

 
$
(86
)
 
$

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 and margin deposits and certain of our cash balances.
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.
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, 2012 and 2011, we had cash and cash equivalents of $131 million and $306 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash
Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.
The table below represents the components of our restricted cash as of December 31, 2012 and 2011 (in millions):
 
 
2012
 
2011
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
11

 
$
41

 
$
52

 
$
11

 
$
42

 
$
53

Construction/major maintenance
32

 
14

 
46

 
33

 
10

 
43

Security/project/insurance
101

 
3

 
104

 
79

 

 
79

Other
49

 
2

 
51

 
16

 
3

 
19

Total
$
193

 
$
60

 
$
253

 
$
139

 
$
55

 
$
194

___________
(1)
At both December 31, 2012 and 2011, amounts restricted for 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, 2012 and 2011, we had inventory of $301 million and $294 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
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, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. 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, First Lien Term Loans and Corporate Revolving Facility. Our interest rate swap agreements relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. 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 and routine repairs and maintenance, have been capitalized since our purchase date.
We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis 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 rotable equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and the composite depreciation method for most of all of the other natural gas-fired power plant asset groups and Geysers Assets.
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. 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. 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. 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 2012 and 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.
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, 2012 and 2011, our asset retirement obligation liabilities were $38 million and $27 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.
Revenue Recognition
Our operating revenues are comprised 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, other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging and optimization activities;
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.
Realized and Unrealized Revenues from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations.   

Unrealized Mark-to-Market Gain (Loss) The changes in the unrealized mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements related to power plants under construction, at December 31, 2012, are as follows (in millions):
2013
$
548

2014
446

2015
455

2016
397

2017
359

Thereafter
2,078

Total
$
4,283

 
 

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 comprised 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 our marketing, hedging and optimization activities and realized settlements 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.
Realized and Unrealized Expenses from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas purchase and sales commodity contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated Statements of Operations.

Unrealized Mark-to-Market (Gain) Loss The changes in the unrealized mark-to-market value of natural gas-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense.
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, the FASB issued Accounting Standards Update 2011-04, “Fair Value Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating to fair value measurements. The update stems from the FASB and the International Accounting Standards Board project to develop common requirements for measuring fair value and for disclosing information about fair value measurements. The update did not impact any of our fair value measurements but did require disclosure of the following:
quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy;
for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and
the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.
The new requirements relating to fair value measurements are prospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption prohibited. We adopted all of the requirements related to this update at January 1, 2012. Since this update did not impact any of our fair value measurements and only required additional disclosures, adoption of this standard did not have a material impact on our financial condition, results of operations or cash flows.
Disclosures about Offsetting Assets and Liabilities — In December 2011, the FASB issued Accounting Standards Update 2011-11, “Balance Sheet - Disclosures about Offsetting Assets and Liabilities” to enhance disclosure requirements relating to the offsetting of assets and liabilities on an entity's balance sheet. The update requires enhanced disclosures regarding assets and liabilities that are presented net or gross in the statement of financial position when the right of offset exists, or that are subject to an enforceable master netting arrangement. In January 2013, the FASB issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” to provide clarification that the scope previously defined in Accounting Standards Update 2011-11 applies to derivatives, repurchase agreements, reverse repurchase agreements and securities borrowing and lending transactions that are subject to an enforceable master netting arrangement or similar agreement. The new disclosure requirements relating to these updates are retrospective and effective for annual and interim periods beginning on or after January 1, 2013. These updates only require additional disclosures, as such, the adoption of these standards will not have a material impact on our financial condition, results of operations or cash flows.
Comprehensive Income — In February 2013, the FASB issued Accounting Standards Update 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” to amend the reporting of reclassifications out of AOCI to require an entity to report the effect of significant reclassifications out of AOCI on the respective line items in net income if the amount reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. An entity shall provide this information together in one location, either on the face of the statement where net income is presented, or as a separate disclosure in the notes to the financial statements. The new disclosure requirements relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2012, with early adoption permitted. This update only requires additional disclosures, as such, the adoption of this standard will not have a material impact on our financial condition, results of operations or cash flows.
Acquisitions, Divestitures and Discontinued Operations
Acquisitions, Divestitures and Discontinued Operations
Acquisitions, Divestitures and Discontinued Operations
Acquisition of Bosque Energy Center
On November 7, 2012, we, through our indirect, wholly-owned subsidiary Calpine Bosque Energy Center, LLC, completed the purchase of a power plant with a nameplate capacity of 800 MW owned by Bosque Power Co., LLC, for approximately $432 million. The modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment and is located in Central Texas near the unincorporated community of Laguna Park in Bosque County. The site includes a 250 MW generation block with one natural-gas turbine, one heat recovery steam generator and one steam turbine that achieved COD in June 2001 and a 550 MW generation block with two natural-gas turbines that went online in June 2000 as well as two heat recovery steam generators and one steam turbine that achieved COD in June 2011. We funded the $432 million purchase price with cash on hand. The purchase price was primarily allocated to property, plant and equipment. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation nor do we expect to recognize any goodwill as a result of this acquisition.
Conectiv Acquisition
On July 1, 2010, we, through our indirect, wholly-owned subsidiary NDH, completed the Conectiv Acquisition. The assets acquired included 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 NDH Project Debt was repaid in March 2011 with proceeds from borrowings under our 2018 First Lien Term Loans.
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.
The following table summarizes the pro forma operating revenues and net income (loss) attributable to Calpine for 2010 as if the Conectiv Acquisition had occurred on January 1, 2009. The pro forma information has been prepared by adding the preliminary, unaudited historical results of Conectiv, as adjusted for depreciation expense (utilizing the preliminary values assigned to the net assets acquired from Conectiv), interest expense from NDH Project Debt and income taxes to our historical results for the periods indicated below (in millions, except per share amounts).
 
 
2010
Operating revenues
 
$
7,931

Net loss attributable to Calpine
 
$
(83
)
Basic loss per common share attributable to Calpine
 
$
(0.17
)
Diluted loss per common share attributable to Calpine
 
$
(0.17
)

Acquisition of Broad River and South Point Leases
On December 8, 2010, we, through our indirect, wholly-owned 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. The Calpine BRSP project debt was repaid in October 2012 with proceeds from borrowings under our 2019 First Lien Term Loan.
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 power 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 in accordance with U.S. GAAP.
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 power 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 Riverside Energy Center
Our 603 MW Riverside Energy Center had a PPA that provided WP&L an option to purchase the power plant and plant-related assets upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase Riverside Energy Center, LLC, one of our VIEs which owned Riverside Energy Center. The sale closed on December 31, 2012 for approximately $402 million, and we recorded a pre-tax gain of approximately $7 million, which is included in (gain) on sale of assets, net on our Consolidated Statements of Operations. We expect to use the sale proceeds for our capital allocation activities and for general corporate purposes. The sale of Riverside Energy Center did not meet the criteria for treatment as discontinued operations.
Sale of Broad River
On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the sale of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This transaction resulted in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South Carolina, and includes a five year consulting agreement with the buyer. We recorded a pre-tax gain of approximately $215 million in December 2012, which is included in (gain) on sale of assets, net on our Consolidated Statements of Operations. We expect to use the sale proceeds for our capital allocation activities and for general corporate purposes. The sale of the Broad River Entities did not meet the criteria for treatment as discontinued operations.
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 the year ended December 31, 2010.
Discontinued Operations
The table below presents the components of our discontinued operations for the period presented (in millions):
 
 
2010
Operating revenues
 
$
92

Gain on disposal of discontinued operations
 
209

Income from discontinued operations before taxes
 
43

Less: Income tax expense
 
59

Discontinued operations, net of tax
 
$
193


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 Statements 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, 2012 and 2011, the components of property, plant and equipment, are stated at cost less accumulated depreciation as follows (in millions):
 
2012
 
2011
 
Depreciable Lives
Buildings, machinery and equipment
$
14,774

 
$
15,074

 
3 – 47 Years
Geothermal properties
1,243

 
1,163

 
13 – 59 Years
Other
142

 
156

 
3 – 47 Years
 
16,159

 
16,393

 
 
Less: Accumulated depreciation
4,390

 
4,158

 
 
 
11,769

 
12,235

 
 
Land
98

 
91

 
 
Construction in progress
1,138

 
693

 
 
Property, plant and equipment, net
$
13,005

 
$
13,019

 
 

Total depreciation expense, including amortization of leased assets, recorded in income from operations and discontinued operations for the years ended December 31, 2012, 2011 and 2010, was $557 million, $560 million and $568 million, respectively.
We have various debt instruments that are collateralized by our property, plant and equipment. See Note 6 for a detailed discussion of such instruments.
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.
Geothermal Properties
This component primarily includes our Geysers Assets.
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 $38 million, $24 million and $15 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
5.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the year ended December 31, 2012. 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.
VIE with a Purchase Option — OMEC has an agreement that provides a third party a fixed price option to purchase power plant assets exercisable in the year 2019 with an aggregate capacity of 608 MW. This purchase option limits the risk and reward of our ownership and, thus, constitutes 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.
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
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 8,255 MW and 11,391 MW, at December 31, 2012 and 2011, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. In addition to amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of $20 million and $87 million for the years ended December 31, 2012 and 2011, respectively. During the year ended December 31, 2010, we 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, we 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.
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
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. At December 31, 2012 and 2011, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of December 31, 2012
 
2012
 
2011
Greenfield LP
50%
 
$
69

 
$
72

Whitby
50%
 
12

 
8

Total investments
 
 
$
81

 
$
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, 2012 and 2011, equity method investee debt was approximately $448 million and $462 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $224 million and $231 million at December 31, 2012 and 2011, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2012, 2011 and 2010, 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 and distributions for the years indicated (in millions):
 
(Income) from Unconsolidated
Investments in Power Plants
 
Distributions
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Greenfield LP
$
(17
)
 
$
(12
)
 
$
(8
)
 
$
22

 
$
2

 
$
6

Whitby
(11
)
 
(9
)
 
(8
)
 
7

 
4

 
5

Total
$
(28
)
 
$
(21
)
 
$
(16
)
 
$
29

 
$
6

 
$
11



Greenfield LP — Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd. and contains the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada which is operated by a third party. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Greenfield LP holds an 18-year term loan with an original principal 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 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.
Significant Unconsolidated Subsidiaries — Greenfield LP and Whitby met the criteria of significant unconsolidated subsidiaries for the year ended December 31, 2012, based upon the relationship of our equity income from our investment in these subsidiaries, when combined, to our consolidated net income before taxes. Aggregated summarized financial data for our unconsolidated subsidiaries is set forth below (in millions):
Condensed Combined Balance Sheets
of Our Unconsolidated Subsidiaries
December 31, 2012 and 2011

 
2012
 
2011
Assets:
 
 
 
Cash and cash equivalents

$
64

 
$
76

Current assets

30

 
37

Property, plant and equipment, net
648

 
656

Other assets
4

 
3

Total assets

$
746

 
$
772

Liabilities:
 
 
 
Current maturities of long-term debt
$
25

 
$
24

Current liabilities

36

 
47

Long-term debt

423

 
438

Long-term derivative liabilities
84

 
85

Total liabilities
568

 
594

Member’s interest

178

 
178

Total liabilities and member’s interest

$
746

 
$
772


Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
For the Years Ended December 31, 2012, 2011 and 2010

 
2012
 
2011
 
2010
Revenues
$
247

 
$
277

 
$
228

Operating expenses
171

 
208

 
183

Income from operations
76

 
69

 
45

Interest expense, net of interest income
27

 
30

 
27

Other (income) expense, net
(2
)
 
2

 

Net income
$
51

 
$
37

 
$
18

Debt
Debt
Debt
Our debt at December 31, 2012 and 2011, was as follows (in millions):
 
2012
 
2011
First Lien Notes(1)
$
5,303

 
$
5,892

First Lien Term Loans(1)
2,463

 
1,646

Project financing, notes payable and other(1)
1,789

 
1,691

CCFC Notes
978

 
972

Capital lease obligations
217

 
224

Total debt
10,750

 
10,425

Less: Current maturities
115

 
104

Debt, net of current portion
$
10,635

 
$
10,321

_____________
(1)
During the fourth quarter of 2012, we redeemed 10% of the aggregate principal amount of our First Lien Notes and repaid project debt with proceeds received from the issuance of our 2019 First Lien Term Loan.
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2012, are as follows (in millions):
 
2013
$
115

2014
188

2015
153

2016
1,162

2017
1,597

Thereafter
7,580

Total debt
10,795

Less: Discount
45

Total
$
10,750


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)
 
2012
 
2011
 
2012
 
2011
2017 First Lien Notes
$
1,080

 
$
1,200

 
7.5
%
 
7.5
%
2019 First Lien Notes
360

 
400

 
8.2

 
8.2

2020 First Lien Notes
983

 
1,092

 
8.1

 
8.1

2021 First Lien Notes
1,800

 
2,000

 
7.7

 
7.7

2023 First Lien Notes
1,080

 
1,200

 
8.0

 
8.0

Total First Lien Notes
$
5,303

 
$
5,892

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Term Loans and Corporate Revolving Facility, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes.
Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:
incur or guarantee additional first lien indebtedness;
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
enter into sale and leaseback transactions;
create or incur liens; and
consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.
On October 9, 2012, we issued notice to the holders of our First Lien Notes of our intent to redeem 10% of the aggregate principal amount of each series of our existing First Lien Notes. On November 7, 2012, we completed the redemption at a redemption price of 103% of the principal amount redeemed, plus accrued and unpaid interest. This redemption was funded using a portion of the proceeds received from the issuance of the 2019 First Lien Term Loan discussed further below.
First Lien Term Loans
Our First Lien Term Loans provide for senior secured term loan facilities and bear interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the First Lien Term Loans credit agreements), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%. An aggregate amount equal to 0.25% of the aggregate principal amount of the First Lien Term Loans will be payable at the end of each quarter with the remaining balance payable on the maturity date. The First Lien Term Loans are subject to certain qualifications and exceptions, similar to our First Lien Notes. The 2018 First Lien Term Loans have a maturity date of April 1, 2018.
On October 9, 2012, we entered into and borrowed $835 million under our 2019 First Lien Term Loan, which bears interest at the same rate as our First Lien Term Loans (discussed above). We used the net proceeds received to redeem 10% of the aggregate principal amount of each series of our existing First Lien Notes at a redemption price of 103% of the principal amount redeemed and to repay project debt totaling $218 million, plus accrued and unpaid interest for each. The 2019 First Lien Term Loan allows us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with fixed interest rates ranging from 7.25% to 8.0% with a corporate level term loan carrying a lower variable interest rate currently at 4.5% and to repay variable rate project debt.
The 2019 First Lien Term Loan carries substantially the same terms as the 2018 First Lien Term Loans and matures on October 9, 2019. The 2019 First Lien Term Loan also contains substantially similar covenants, qualifications, exceptions and limitations as the 2018 First Lien Term Loans and First Lien Notes. We recorded debt extinguishment costs of approximately $18 million associated with the redemption premium, the write-off of unamortized deferred financing costs and debt premium and discount during the fourth quarter of 2012.
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2012
 
2011
 
2012
 
2011
2018 First Lien Term Loans
$
1,630

 
$
1,646

 
4.7
%
 
4.7
%
2019 First Lien Term Loan
833

 

 
4.7

 

Total First Lien Term Loans
$
2,463

 
$
1,646

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
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)
 
2012
 
2011
 
2012
 
2011
Russell City Project Debt due 2023
$
507

 
$
244

 
3.6
%
 
4.1
%
Steamboat due 2017
428

 
437

 
6.8

 
6.6

OMEC due 2019
345

 
355

 
6.8

 
6.8

Los Esteros Project Debt due 2023
209

 
83

 
3.5

 
3.8

Pasadena(2)
160

 
185

 
8.9

 
8.8

Bethpage Energy Center 3 due 2020-2025(3)
93

 
98

 
7.0

 
7.0

Gilroy note payable due 2014
33

 
49

 
10.8

 
10.6

Calpine BRSP due 2014(4)

 
232

 

 
5.7

Other
14

 
8

 

 

Total
$
1,789

 
$
1,691

 
 
 
 
_____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount or premium.
(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)
During the fourth quarter of 2012, we repaid the Calpine BRSP project debt with proceeds received from the issuance of our 2019 First Lien Term Loan.
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.
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 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 2012 and 2011.
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, 2012 (in millions):
 
Sale-Leaseback Transactions(1)
 
Capital Lease
 
Total
2013
$
37

 
$
42

 
$
79

2014
25

 
43

 
68

2015
25

 
38

 
63

2016
25

 
41

 
66

2017
17

 
38

 
55

Thereafter
127

 
161

 
288

Total minimum lease payments
256

 
363

 
619

Less: Amount representing interest
96

 
146

 
242

Present value of net minimum lease payments
$
160

 
$
217

 
$
377

____________
(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 36 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 December 31, 2012 and 2011, the asset balances for the leased assets totaled approximately $880 million and $879 million with accumulated amortization of $312 million and $318 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 at December 31, 2012 and 2011 (in millions):
 
2012
 
2011
Corporate Revolving Facility
$
243

 
$
440

CDHI
253

 
193

Various project financing facilities
130

 
130

Total
$
626

 
$
763


The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 2.00% to 2.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers’ Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 3.00% to 3.25%. Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.50% to 0.75% on the unused amount of commitments under the Corporate Revolving Facility.
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures on December 10, 2015.
The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.
CDHI
We also have a letter of credit facility related to CDHI. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016. As a result of the completion of the sale of Riverside Energy Center, LLC, a wholly-owned subsidiary of CDHI, on December 31, 2012, we are required to cash collateralize letters of credit issued in excess of $225 million until replacement collateral is contributed to the CDHI collateral package which we are in the process of arranging. At December 31, 2012, we had $28 million of cash collateral posted in support of outstanding letters of credit under our CDHI letter of credit facility. We do not believe that this change will have a material impact on our liquidity.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The following table details the fair values and carrying values of our debt instruments at December 31, 2012 and 2011 (in millions):
 
2012
 
2011
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
5,863

 
$
5,303

 
$
6,219

 
$
5,892

First Lien Term Loans
2,489

 
2,463

 
1,615

 
1,646

Project financing, notes payable and other(1)
1,599

 
1,629

 
1,467

 
1,504

CCFC Notes
1,075

 
978

 
1,070

 
972

Total
$
11,026

 
$
10,373

 
$
10,371

 
$
10,014

____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
On January 1, 2012, we adopted Accounting Standards Update 2011-04 “Fair Value Measurement” which requires the categorization by level of the fair value hierarchy for items not measured at fair value on our Consolidated Balance Sheets but for which fair value is required to be disclosed. We measure the fair value of our First Lien Notes, First Lien Term Loans and CCFC Notes using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
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 our 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); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of natural gas swaps, futures and options traded on the NYMEX.
Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are primarily industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our or our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. In cases where there is no corroborating market information available to support significant model inputs, we initially use the transaction price as the best estimate of fair value. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.
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. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2012
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,502

 
$

 
$

 
$
1,502

Margin deposits
196

 

 

 
196

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
385

 

 

 
385

Commodity forward contracts(2)

 
24

 
24

 
48

Interest rate swaps

 
4

 

 
4

Total assets
$
2,083

 
$
28

 
$
24

 
$
2,135

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
11

 
$

 
$

 
$
11

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
424

 

 

 
424

Commodity forward contracts(2)

 
18

 
8

 
26

Interest rate swaps

 
200

 

 
200

Total liabilities
$
435

 
$
218

 
$
8

 
$
661

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

 
$

 
$

 
$
1,415

Margin deposits
140

 

 

 
140

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

 

 

 
1,043

Commodity forward contracts(2)

 
74

 
37

 
111

Interest rate swaps

 
10

 

 
10

Total assets
$
2,598

 
$
84

 
$
37

 
$
2,719

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

 
$

 
$

 
$
34

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
899

 

 

 
899

Commodity forward contracts(2)

 
184

 
20

 
204

Interest rate swaps

 
320

 

 
320

Total liabilities
$
933

 
$
504

 
$
20

 
$
1,457

___________
(1)
As of December 31, 2012 and 2011, we had cash equivalents of $1,274 million and $1,249 million included in cash and cash equivalents and $228 million and $166 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the years ended December 31, 2012, 2011 and 2010 (in millions):
 
2012
 
2011
 
2010
Balance, beginning of period
$
17

 
$
30

 
$
38

Realized and unrealized gains (losses):
 
 
 
 
 
Included in net income:
 
 
 
 
 
Included in operating revenues(1)
8

 
5

 
7

Included in fuel and purchased energy expense(2)

 

 

Included in OCI

 
2

 
2

Purchases, issuances and settlements:
 
 
 
 
 
Purchases
3

 

 

Issuances
(1
)
 

 

Settlements
(11
)
 
(18
)
 
(20
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
Transfers into level 3(4)

 
(2
)
 

Transfers out of level 3(5)

 

 
3

Balance, end of period
$
16

 
$
17

 
$
30

Change in unrealized gains relating to instruments still held at end of period
$
8

 
$
5

 
$
7

___________
(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, 2012, 2011 and 2010.
(4)
There were no significant transfers into level 3 for the years ended December 31, 2012 and 2010. 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.
(5)
We had no significant transfers out of level 3 for the years ended December 31, 2012 and 2011. There were $3 million in losses transferred out of level 3 into level 2 for the year ended December 31, 2010 due to changes in market liquidity in various power markets.
At December 31, 2012, the derivative instruments classified as level 3 primarily included a longer-term OTC traded commodity contract extending through 2014. This contract is classified as level 3 because the contract terms exceed the period for which liquid market rate information is available. As such, the fair value of the contract incorporates extrapolation assumptions made in the determination of the market price for future delivery periods in which applicable commodity prices were either not observable or lacked corroborative market data. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices; however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 net fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2012:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
December 31, 2012
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
11

 
Discounted cash flow
 
Market price (per MWh)
 
$23.75 — $53.82/MWh
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, 2012, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 11 years.
As of December 31, 2012 and 2011, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
2012
 
2011
Power (MWh)
 
(16
)
 
(21
)
Natural gas (MMBtu)
 
66

 
(200
)
Interest rate swaps(1)
 
$
1,602

 
$
5,639

____________
(1)
Approximately $4.1 billion at December 31, 2011 was related to hedges of our First Lien Credit Facility’s variable rate debt that was converted to fixed rate debt. On March 26, 2012, we terminated the interest rate swaps formerly hedging our First Lien Credit Facility.
Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of December 31, 2012, was $5 million for which we have posted collateral of $1 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $1 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. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-to-market gain/loss on our Consolidated Statements of Operations and could create more volatility in our earnings. Revenues and fuel costs derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Although we have discontinued the application of hedge accounting treatment for our commodity derivative instruments, prior to this change and for our interest rate swaps, hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) on our Consolidated 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 and are separately stated on our Consolidated Statements of Operations in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and swaps) and fuel and purchased energy expense (for natural gas contracts and swaps). Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as 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, unrealized losses of approximately $91 million in AOCI related to the interest rate swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into earnings as an additional loss on interest rate derivatives during 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 earnings 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 earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Statement of Operations for the year ended December 31, 2012, and approximately $142 million reflected the realization of losses recorded in prior periods.
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, 2012 and 2011 (in millions):
 
December 31, 2012
  
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$

 
$
339

 
$
339

Long-term derivative assets
4

 
94

 
98

Total derivative assets
$
4

 
$
433

 
$
437

 
 
 
 
 
 
Current derivative liabilities
$
40

 
$
317

 
$
357

Long-term derivative liabilities
160

 
133

 
293

Total derivative liabilities
$
200

 
$
450

 
$
650

Net derivative assets (liabilities)
$
(196
)
 
$
(17
)
 
$
(213
)

 
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, 2012
 
December 31, 2011
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments(1):
 
 
 
 
 
 
 
Interest rate swaps
$
4

 
$
184

 
$
10

 
$
149

Commodity instruments

 

 
51

 
18

Total derivatives designated as cash flow hedging instruments
$
4

 
$
184

 
$
61

 
$
167

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
16

 
$

 
$
171

Commodity instruments
433

 
450

 
1,103

 
1,085

Total derivatives not designated as hedging instruments
$
433

 
$
466

 
$
1,103

 
$
1,256

Total derivatives
$
437

 
$
650

 
$
1,164

 
$
1,423


____________
(1)
Includes accumulated fair value of derivative instruments as of the date hedge accounting was discontinued, net of amortized fair value for settlement periods which have transpired.
Derivatives Included on Our Consolidated 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 in our earnings.
The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010 (in millions):
 
2012
 
2011
 
2010
Realized gain (loss)(1)
 
 
 
 
 
Interest rate swaps
$
(157
)
 
$
(193
)
 
$
(31
)
Commodity derivative instruments
387

 
143

 
114

Total realized gain (loss)
$
230

 
$
(50
)
 
$
83

 
 
 
 
 
 
Unrealized gain (loss)(2)
 
 
 
 
 
Interest rate swaps
$
154

 
$
55

 
$
(199
)
Commodity derivative instruments
(82
)
 
(25
)
 
143

Total unrealized gain (loss)
$
72

 
$
30

 
$
(56
)
Total mark-to-market activity, net
$
302

 
$
(20
)
 
$
27

___________
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
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 earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
2012
 
2011
 
2010
Realized and unrealized gain (loss)
 
 
 
 
 
Derivatives contracts included in operating revenues
$
187

 
$
(20
)
 
$
(19
)
Derivatives contracts included in fuel and purchased energy expense
118

 
138

 
276

Interest rate swaps included in interest expense
11

 
7

 
(7
)
Loss on interest rate derivatives
(14
)
 
(145
)
 
(223
)
Total mark-to-market activity, net
$
302

 
$
(20
)
 
$
27


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, 2012 and 2011 (in millions):
 
 
Gains (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(1)
 
Gain (Loss) Reclassified from
AOCI into Income (Ineffective
Portion)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Interest rate swaps
$
(43
)
 
$
(23
)
 
$
(32
)
(2) 
$
(138
)
(2) 
$

 
$
(1
)
Commodity derivative instruments
(38
)
 
(71
)
 
52

(3) 
163

(3) 
2

 
(2
)
Total
$
(81
)
 
$
(94
)
 
$
20

 
$
25

  
$
2

 
$
(3
)
____________
(1)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $242 million and $172 million at December 31, 2012 and 2011, respectively.
(2)
Reclassification of losses from OCI to earnings consisted of $32 million from the reclassification of interest rate contracts due to settlement for each of the years ended December 31, 2012 and 2011, $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 for the year ended December 31, 2011.
(3)
Included in Commodity revenue and Commodity expense on our Consolidated Statements of Operations.
As a result of our election to discontinue hedge accounting treatment for our commodity derivatives accounted for as cash flow hedges, the fair value of our commodity derivative instruments that previously resided in AOCI on the de-designation date was reclassified to earnings during 2012 as the related hedged transactions affected earnings. Thus, there is no fair value amounts related to commodity derivatives remaining in AOCI at December 31, 2012. We estimate that pre-tax net losses of $41 million (comprised of amounts related to interest rate swaps) 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 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, 2012 and 2011 (in millions):
 
2012
 
2011
Margin deposits(1)
$
196

 
$
140

Natural gas and power prepayments
35

 
42

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
231

 
$
182

 
 
 
 
Letters of credit issued
$
484

 
$
581

First priority liens under power and natural gas agreements
14

 
1

First priority liens under interest rate swap agreements
206

 
318

Total letters of credit and first priority liens with our counterparties
$
704

 
$
900

 
 
 
 
Margin deposits held by us posted by our counterparties(1)(3)
$
11

 
$
34

Letters of credit posted with us by our counterparties
1

 

Total margin deposits and letters of credit posted with us by our counterparties
$
12

 
$
34

___________
(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, 2012 and 2011, $211 million and $162 million, respectively, were included in margin deposits and other prepaid expense and $20 million and $20 million, respectively, were included in other assets on our Consolidated Balance Sheets.
(3)
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, 2012, 2011 and 2010, are as follows (in millions):
 
2012
 
2011
 
2010
U.S.
$
194

 
$
(232
)
 
$
(226
)
International
24

 
20

 
(4
)
Total
$
218

 
$
(212
)
 
$
(230
)

The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2012, 2011 and 2010, consisted of the following (in millions):
 
2012
 
2011
 
2010
 
Current:
 
 
 
 
 
 
Federal
$
(12
)
 
$
(16
)
 
$
(1
)
 
State
16

 
12

 
10

 
Foreign
14

 
3

 
3

 
Total current
18

 
(1
)
 
12

 
Deferred:
 
 
 
 
 
 
Federal
11

 
(33
)
 
(70
)
 
State
(5
)
 
9

 

 
Foreign
(5
)
 
3

 
(10
)
 
Total deferred
1

 
(21
)
 
(80
)
 
Total income tax expense (benefit)
$
19

 
$
(22
)
 
$
(68
)
(1 
) 
_________
(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, 2012, 2011 and 2010, 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, 2012, 2011 and 2010, is as follows:
 
2012
 
2011
 
2010
Federal statutory tax expense (benefit) rate
35.0
 %
 
(35.0
)%
 
(35.0
)%
State tax expense, net of federal benefit
3.2

 
6.5

 
2.8

Depletion in excess of basis
(0.2
)
 

 
(1.3
)
Preferred interest expense
2.0

 
0.4

 
0.5

Federal refunds
(4.7
)
 

 

Valuation allowances against future tax benefits
(32.3
)
 
56.7

 
33.6

Valuation allowances related to reconsolidation of CCFC

 
(36.0
)
 

Valuation allowances related to foreign taxes
(8.2
)
 

 

Foreign taxes
3.7

 
(0.9
)
 
9.9

Non-deductible reorganization items
0.1

 
0.5

 
0.3

Intraperiod allocation
4.6

 
19.9

 
(40.1
)
Bankruptcy settlement

 
(15.7
)
 

Change in unrecognized tax benefits
5.1

 
(6.6
)
 
0.6

Permanent differences and other items
0.4

 
(0.2
)
 
(0.9
)
Effective income tax expense (benefit) rate
8.7
 %
 
(10.4
)%
 
(29.6
)%

Deferred Tax Assets and Liabilities
The components of the deferred income taxes as of December 31, 2012 and 2011, are as follows (in millions):
 
2012
 
2011
Deferred tax assets:
 
 
 
NOL and credit carryforwards
$
3,073

 
$
3,290

Taxes related to risk management activities and derivatives
90

 
58

Reorganization items and impairments
315

 
318

Foreign capital losses
25

 
24

Other differences
60

 
26

Deferred tax assets before valuation allowance
3,563

 
3,716

Valuation allowance
(2,222
)
 
(2,336
)
Total deferred tax assets
1,341

 
1,380

Deferred tax liabilities: property, plant and equipment
(1,316
)
 
(1,364
)
Net deferred tax asset
25

 
16

Less: Current portion deferred tax liability
(3
)
 
(2
)
Less: Non-current deferred tax asset
28

 
18

Deferred income tax liability, non-current
$

 
$


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 filed a consolidated federal income tax return for the year ended December 31, 2011 that included 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 year ended December 31, 2010, 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 years ended December 31, 2012, 2011 and 2010 (in millions).
 
2012
 
2011
 
2010
Intraperiod tax allocation expense (benefit) included in continuing operations
$
9

 
$
42

 
$
(86
)
Intraperiod tax allocation expense included in discountinued operations
$

 
$

 
$
59

Intraperiod tax allocation expense (benefit) included in OCI
$
(9
)
 
$
(45
)
 
$
27

NOL Carryforwards  Our NOL carryforwards consist primarily of federal NOL carryforwards of approximately $7.3 billion, which expire between 2023 and 2031, and NOL carryforwards in 33 states and the District of Columbia totaling approximately $4.0 billion, which expire between 2013 and 2031, 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, 2012, approximately $2.4 billion of our $7.3 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 $7.1 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.
Deferred tax assets relating to tax benefits of employee stock-based compensation do not reflect stock options exercised and restricted stock that vested in 2012. Some stock option exercises and restricted stock vestings result in tax deductions in excess of previously recorded deferred tax benefits based on the equity award value at the grant date. Although these additional tax benefits or “windfalls” are reflected in net operating tax carryforwards pursuant to accounting for stock-based compensation under U.S. GAAP, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable, which will not occur for Calpine until a future period. Accordingly, since the tax benefit does not reduce our current taxes payable in 2012 due to NOL carryforwards, these “windfall” tax benefits are not reflected in our NOL in deferred tax assets for 2012. Windfalls included in NOL carryforwards, but not reflected in deferred tax assets as of December 31, 2012 were $10 million.
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 date 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 in 2011. The result did not have an impact on our income tax expense in 2011. We estimate that approximately $117 million of our state NOLs expired unutilized during 2012 as a result of statutory state limitations relating to the time period NOLs can be carried forward, and accordingly, we reduced our deferred tax asset and made an equal reduction in our valuation allowance. The reduction did not have an impact to our income tax expense in 2012. We will likely make future annual adjustments to our state NOLs that have expired or are limited under Section 382 of the IRC.
In 2011, 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 of certain bankruptcy claims 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 in 2011.
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 IRS examination regardless of when the NOLs occurred. Due to significant NOLs, any adjustment of state returns or federal returns 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. The CRA concluded that there were no adjustments on two of the subsidiaries, but further review was required on the remaining two subsidiaries. On April 23, 2012, the remaining two subsidiaries received proposed adjustments from the CRA regarding our transfer pricing positions. On June 21, 2012, we met with the CRA to discuss their proposed adjustments and provided clarification where we believed it was needed. In July 2012, we received additional questions from the CRA as a result of our meeting, and we responded to their request in September and October 2012. In December 2012, we received and responded to additional questions from the CRA. In January 2013, we received an adjusted reassessment on one of the two transfer pricing issues that we are disputing with the CRA and are currently evaluating the merits of the adjusted reassessment. If accepted, any adjustments to our transfer pricing would increase taxable income and would be offset entirely by existing NOL's to which a valuation allowance has been applied. Any interest assessments resulting from acceptance of the CRA offer would be immaterial.
We continue to evaluate the remaining proposed adjustments on our other Canadian subsidiary; however, based on our current analysis which is supported by our tax advisors, we believe that our transfer pricing positions and policies are appropriate, and we intend to challenge the CRA’s proposed adjustments. If we are unsuccessful in our challenge, any adjustment to Canadian taxable income would first be offset against the existing NOLs that are available; however, we do not believe any reassessment resulting in an adjustment to taxable income which is greater than our existing NOLs, or including interest or penalties which cannot be offset by existing NOLs, would have a material adverse effect on our financial condition, results of operations or cash flows.
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, 2012, we have provided a valuation allowance of approximately $2.2 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 $114 million, $50 million and $186 million for the years ended December 31, 2012, 2011 and 2010, respectively; all primarily related to changes in our estimates of our ability to utilize our NOL carryforwards.
Unrecognized Tax Benefits
At December 31, 2012, we had unrecognized tax benefits of $92 million. If recognized, $36 million of our unrecognized tax benefits could impact the annual effective tax rate and $56 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 $24 million for income tax matters at December 31, 2012. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Statements of Operations. We believe that it is reasonably possible that a decrease within the range of approximately nil and $28 million in unrecognized tax benefits could occur within the next 12 months primarily related to state and foreign tax issues.
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2012, 2011 and 2010, is as follows (in millions):
 
2012
 
2011
 
2010
Balance, beginning of period
$
(74
)
 
$
(88
)
 
$
(98
)
Increases related to prior year tax positions
(19
)
 

 
(1
)
Decreases related to prior year tax positions
1

 
1

 
11

Decrease related to lapse of statute of limitations

 
13

 

Balance, end of period
$
(92
)
 
$
(74
)
 
$
(88
)

U.S. Federal Income Tax Refund
In 2004, we deducted a portion of our foreign dividends as allowed by the IRC when we filed our federal income tax return. Upon further review and analysis, we determined our foreign dividends should have been offset against our current 2004 operating loss. In 2009, we filed an amended federal income tax return that reflected this change and would result in a refund of approximately $10 million. This amended federal return has been under audit by the IRS since it was filed. In October 2012, the IRS approved our amended tax return, and we received a refund of approximately $13 million which included approximately $3 million in accrued interest. The benefit of this refund is reflected in our Consolidated Financial Statements in the fourth quarter of 2012.
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 entire 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, 2012, 2011 and 2010, are as follows (shares in thousands):
 
2012
 
2011
 
2010
Diluted weighted average shares calculation:
 
 
 
 
 
Weighted average shares outstanding (basic)
467,752

 
485,381

 
486,044

Share-based awards
3,591

 

 
1,250

Weighted average shares outstanding (diluted)
471,343

 
485,381

 
487,294


We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2012, 2011 and 2010, because they were anti-dilutive (shares in thousands):
 
2012
 
2011
 
2010
Share-based awards
10,302

 
15,260

 
14,883

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, 2012, 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 $25 million, $24 million and $24 million for the years ended December 31, 2012, 2011 and 2010, 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, 2012, 2011 and 2010. At December 31, 2012, there was unrecognized compensation cost of $6 million related to options, $25 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 0.8 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, 2012, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2011
17,665,902

 
$
17.32

 
4.8
 
$
26

Granted
898,115

 
$
15.35

 
 
 
 
Exercised
348,500

 
$
14.94

 
 
 
 
Forfeited
187,716

 
$
13.42

 
 
 
 
Expired
165,300

 
$
17.77

 
 
 
 
Outstanding — December 31, 2012
17,862,501

 
$
17.30

 
4.0
 
$
42

Exercisable — December 31, 2012
10,251,149

 
$
19.16

 
3.6
 
$
12

Vested and expected to vest – December 31, 2012
17,588,775

 
$
17.34

 
3.9
 
$
41


The total intrinsic value of our employee stock options exercised was $1 million, nil and nil for the years ended December 31, 2012, 2011 and 2010, respectively. The total cash proceeds received from our employee stock options exercised was $5 million, nil and nil for the years ended December 31, 2012, 2011 and 2010, respectively.
The fair value of options granted during the years ended December 31, 2012, 2011 and 2010, 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.
 
2012
 
2011
 
2010
 
Expected term (in years)(1)
6.5

 
6.5

 
4.0 – 6.5

 
Risk-free interest rate(2)
1.2 – 1.6

%
1.7 – 3.2

%
1.3 – 3.3

%
Expected volatility(3)
27.0 – 30.5

%
31.2 – 44.9

%
31.4 – 37.6

%
Dividend yield(4)

 

 

 
Weighted average grant-date fair value (per option)
$
5.18

 
$
5.49

 
$
1.98

 
___________
(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, 2012, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2011
3,510,358

 
$
12.10

Granted
1,991,894

 
$
15.97

Forfeited
297,166

 
$
13.70

Vested
1,071,049

 
$
10.17

Nonvested — December 31, 2012
4,134,037

 
$
14.33


The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2012, 2011 and 2010, was approximately $20 million, $7 million and $4 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 $11 million, $10 million and $9 million for the years ended December 31, 2012, 2011 and 2010, 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 eligible 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 prior service cost; however, we are responsible for benefits for services after July 1, 2010 and future compensation increases related to prior 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, 2012 and 2011, our pension assets, liabilities and related costs were not material to us. As of December 31, 2012 and 2011, there were approximately $12 million and $10 million in plan assets and approximately $21 million and $18 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2012 and 2011, was approximately $9 million and $8 million, respectively. For the years ended December 31, 2012, 2011 and 2010, we recognized net periodic benefit costs of approximately $1 million, $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, 2012 and 2011, the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $1 million and $3 million, 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 2012 and 2011, we made contributions of approximately $2 million and $3 million, respectively, and estimated contributions to the pension plan are expected to be approximately $1 million in 2013. Estimated future benefit payments to participants in each of the next five years are expected to be approximately $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, 2012 and 2011, was 492,495,100 shares and 490,468,815 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2012 and 2011, was 457,048,970 shares and 481,743,738 shares, respectively. The table below summarizes our common stock activity for the years ended December 31, 2012, 2011 and 2010.
 
Shares
Issued
 
Shares
Held in
Treasury
 
Shares
Held in
Reserve
 
Total
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

Shares issued under Calpine Equity Incentive Plans
2,026,285

 
(284,376
)
 

 
1,741,909

Share repurchase program

 
(26,436,677
)
 

 
(26,436,677
)
Balance, December 31, 2012
492,495,100

 
(35,446,130
)
 

 
457,048,970


Treasury Stock
As of December 31, 2012 and 2011, we had treasury stock of 35,446,130 shares and 8,725,077 shares, respectively, with a cost of $594 million and $125 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. In April 2012, our Board of Directors authorized us to double the size of our share repurchase program, increasing our permitted cumulative repurchases to $600 million in shares of our common stock. As of the filing of this Report, we have completed our previously announced $600 million share repurchase program, having repurchased a total of 35,568,833 shares of our outstanding common stock at an average price paid of $16.87 per share. In February 2013, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock, bringing the cumulative authorization total to $1.0 billion. 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. All treasury stock is held at cost.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
Long-Term Service Agreements
As of December 31, 2012, the total estimated commitments for LTSAs associated with turbines installed or in storage were approximately $68 million. These commitments are payable over the terms of the respective agreements, which range from 1 to 5 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, which include renewal options or purchase options at fair value and contain customary restrictions on dividends up to Calpine Corporation, 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
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
Total
Land and other operating leases
various
 
$
14

 
$
14

 
$
14

 
$
15

 
$
15

 
$
228

 
$
300

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
3

 
$

 
$

 
$

 
$

 
$
10

KIAC
2000
 
24

 
24

 
23

 
22

 
22

 
52

 
167

Total power plant leases
 
 
$
31

 
$
27

 
$
23

 
$
22

 
$
22

 
$
52

 
$
177

Total leases
 
 
$
45

 
$
41

 
$
37

 
$
37

 
$
37

 
$
280

 
$
477


During the years ended December 31, 2012, 2011 and 2010, rent expense for power plant and land and other operating leases amounted to $51 million, $53 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, 2012, 2011 and 2010, were $22 million, $22 million and $25 million, respectively.
Office Leases
We lease our corporate and regional offices under noncancellable operating leases extending through 2020. Future minimum lease payments under these leases are as follows (in millions):
2013
$
12

2014
12

2015
12

2016
12

2017
12

Thereafter
31

Total
$
91


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, 2012, 2011 and 2010, rent expense for noncancellable operating leases was $12 million, $13 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, 2012, we had future commitments of approximately $3.0 billion for natural gas purchases under contracts with terms from 1 to 13 years, and one contract with a term of 29 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, 2012, 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
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
Total
Guarantee of subsidiary debt(1)
 
$
47

 
$
36

 
$
37

 
$
36

 
$
26

 
$
209

 
$
391

Standby letters of credit(2)(4)
 
536

 
41

 

 

 
19

 
30

 
626

Surety bonds(3)(4)(5)
 

 

 

 

 

 
4

 
4

 Guarantee of subsidiary operating lease payments(4)
 
7

 
3

 

 

 

 

 
10

Total
 
$
590

 
$
80

 
$
37

 
$
36

 
$
45

 
$
243

 
$
1,031

____________
(1)
Represents Calpine Corporation guarantees of certain 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, 2012, $3 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 and effectively guarantee our future performance under certain agreements.
Asset Acquisition and Disposition Agreements — In connection with our purchase and sale agreements, we have frequently provided for indemnification 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, 2012, 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. At the present time, we do not expect that the outcome of any of these proceedings will have a material adverse effect on our financial condition, results of operations or cash flows.
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 on our financial condition, 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 on our financial condition, results of operations or cash flows.
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 operation of our power plants. At the present time, we do not 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.
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, 2012, our reportable segments were West (including geothermal), Texas, North (including Canada) 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 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, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,668

 
$
1,857

 
$
1,280

 
$
673

 
$

 
$
5,478

Intersegment revenues
10

 
61

 
14

 
80

 
(165
)
 

Total operating revenues
$
1,678

 
$
1,918

 
$
1,294

 
$
753

 
$
(165
)
 
$
5,478

Commodity Margin (1)(2)
$
994

 
$
570

 
$
729

 
$
245

 
$

 
$
2,538

Add: Unrealized mark-to-market commodity activity, net and other(3)
(93
)
 
87

 
(14
)
 
(33
)
 
(31
)
 
(84
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
368

 
247

 
206

 
131

 
(30
)
 
922

Depreciation and amortization expense
203

 
142

 
134

 
85

 
(2
)
 
562

Sales, general and other administrative expense
36

 
47

 
28

 
29

 

 
140

Other operating expenses
42

 
5

 
29

 
5

 
(3
)
 
78

(Gain) on sale of assets, net

 

 
(7
)
 
(215
)
 

 
(222
)
(Income) from unconsolidated investments in power plants

 

 
(28
)
 

 

 
(28
)
Income from operations
252

 
216

 
353

 
177

 
4

 
1,002

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
725

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
14

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
45

Income before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
218


 
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)(2)
$
1,061

 
$
469

 
$
704

 
$
240

 
$

 
$
2,474

Add: Unrealized mark-to-market commodity activity, net and other(3)
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
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)(2)
$
1,080

 
$
504

 
$
535

 
$
272

 
$

 
$
2,391

Add: Unrealized mark-to-market commodity activity, net and other
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
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
)
__________
(1)
Our North segment includes Commodity Margin related to Riverside Energy Center, LLC of $73 million , $70 million and $73 million for the years ended December 31, 2012, 2011 and 2010, respectively.
(2)
Our Southeast segment includes Commodity Margin related to Broad River of $52 million, $51 million and $55 million for the years ended December 31, 2012, 2011 and 2010, respectively.
(3)
Includes $1 million and $12 million of lease levelization and $14 million and $8 million of amortization expense for the years ended December 31, 2012 and 2011, respectively, related to contracts that became effective in 2011.
Significant Customer
For the years ended December 31, 2012 and 2011, we had one significant customer, PJM Settlement, Inc., that accounted for more than 10% of our annual consolidated revenues. Our revenues of $713 million and $742 million from PJM Settlement, Inc. for the years ended December 31, 2012 and 2011, respectively, were attributed to our North segment. Our receivables from PJM Settlement, Inc. were $37 million and $28 million as of December 31, 2012 and 2011, respectively. We did not have a customer that accounted for more than 10% of our annual consolidated revenues for the year ended December 31, 2010.
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)
2012
 
 
 
 
 
 
 
Operating revenues
$
1,367

 
$
1,996

 
$
879

 
$
1,236

Income (loss) from operations
$
295

 
$
705

 
$
(193
)
 
$
195

Net income (loss) attributable to Calpine
$
100

 
$
437

 
$
(329
)
 
$
(9
)
Net income (loss) per common share attributable to Calpine — Basic
$
0.22

 
$
0.95

 
$
(0.69
)
 
$
(0.02
)
Net income (loss) per common share attributable to Calpine — Diluted
$
0.22

 
$
0.94

 
$
(0.69
)
 
$
(0.02
)
 
 
 
 
 
 
 
 
2011
 
 
 
 
 
 
 
Operating revenues
$
1,459

 
$
2,209

 
$
1,633

 
$
1,499

Income from operations
$
196

 
$
403

 
$
183

 
$
18

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

 
$
(70
)
 
$
(297
)
Net income (loss) per common share attributable to Calpine — Basic
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Net income (loss) per common share attributable to Calpine — Diluted
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
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, 2012
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
13

 
$
(1
)
 
$
(1
)
 
$
(5
)
 
$
6

Deferred tax asset valuation allowance
2,336

 
(114
)
 

 

 
2,222

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

_____________
(1)
Represents write-offs of accounts considered to be uncollectible and previously reserved.
Summary of Significant Accounting Policies (Policies)
Change in Presentation — We have changed the presentation on our Consolidated Statements of Operations to separately present our Commodity revenue, unrealized mark-to-market gain (loss) and other revenue which are components of operating revenues and our Commodity expense and unrealized mark-to-market (gain) loss which are components of fuel and purchased energy expense. The change in presentation had no impact on our financial condition, results of operations or cash flows.
Reclassification — We have reclassified RGGI compliance and other environmental costs previously recorded in other operating expenses of $10 million and $9 million to Commodity expense on our Consolidated Statements of Operations for the years ended December 31, 2011 and 2010, respectively, to conform to the current year presentation.
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.
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% partnership 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.
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.
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 and margin deposits and certain of our cash balances.
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 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, 2012 and 2011, we had cash and cash equivalents of $131 million and $306 million, respectively, that were subject to such project finance facilities and lease agreements.
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 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.
At December 31, 2012 and 2011, we had inventory of $301 million and $294 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
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, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. 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, First Lien Term Loans and Corporate Revolving Facility. Our interest rate swap agreements relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 9 for a further discussion on our amounts and use of collateral.
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 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 and routine repairs and maintenance, have been capitalized since our purchase date.
We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis 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 rotable equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and the composite depreciation method for most of all of the other natural gas-fired power plant asset groups and Geysers Assets.
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.
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. 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. 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. 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 2012 and 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.
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, 2012 and 2011, our asset retirement obligation liabilities were $38 million and $27 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 operating revenues are comprised 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, other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging and optimization activities;
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.
Realized and Unrealized Revenues from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations.   

Unrealized Mark-to-Market Gain (Loss) The changes in the unrealized mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues.
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 is comprised 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 our marketing, hedging and optimization activities and realized settlements 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.
Realized and Unrealized Expenses from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas purchase and sales commodity contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated Statements of Operations.

Unrealized Mark-to-Market (Gain) Loss The changes in the unrealized mark-to-market value of natural gas-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy 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 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.
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.
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)
Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. The following table summarizes our proportionate ownership interest in jointly-owned power plants:
As of December 31, 2012
 
Ownership Interest
 
Property, Plant & Equipment
 
Accumulated Depreciation
 
Construction in Progress
(in millions, except percentages)
Freestone Energy Center
 
75.0
%
 
$
392

 
$
(124
)
 
$
1

Hidalgo Energy Center
 
78.5
%
 
$
252

 
$
(86
)
 
$

The table below represents the components of our restricted cash as of December 31, 2012 and 2011 (in millions):
 
 
2012
 
2011
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
11

 
$
41

 
$
52

 
$
11

 
$
42

 
$
53

Construction/major maintenance
32

 
14

 
46

 
33

 
10

 
43

Security/project/insurance
101

 
3

 
104

 
79

 

 
79

Other
49

 
2

 
51

 
16

 
3

 
19

Total
$
193

 
$
60

 
$
253

 
$
139

 
$
55

 
$
194

___________
(1)
At both December 31, 2012 and 2011, amounts restricted for debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements related to power plants under construction, at December 31, 2012, are as follows (in millions):
2013
$
548

2014
446

2015
455

2016
397

2017
359

Thereafter
2,078

Total
$
4,283

 
 
Future minimum lease payments under these leases are as follows (in millions):
 
Initial
Year
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
Total
Land and other operating leases
various
 
$
14

 
$
14

 
$
14

 
$
15

 
$
15

 
$
228

 
$
300

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
3

 
$

 
$

 
$

 
$

 
$
10

KIAC
2000
 
24

 
24

 
23

 
22

 
22

 
52

 
167

Total power plant leases
 
 
$
31

 
$
27

 
$
23

 
$
22

 
$
22

 
$
52

 
$
177

Total leases
 
 
$
45

 
$
41

 
$
37

 
$
37

 
$
37

 
$
280

 
$
477

Acquisitions, Divestitures and Discontinued Operations (Tables)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2010
Acquisitions, Divestitures and Discontinued Operations [Abstract]
 
 
Business Acquisition, Pro Forma Information
 
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures
 
Losses Due To Acquisition
 
The following table summarizes the pro forma operating revenues and net income (loss) attributable to Calpine for 2010 as if the Conectiv Acquisition had occurred on January 1, 2009. The pro forma information has been prepared by adding the preliminary, unaudited historical results of Conectiv, as adjusted for depreciation expense (utilizing the preliminary values assigned to the net assets acquired from Conectiv), interest expense from NDH Project Debt and income taxes to our historical results for the periods indicated below (in millions, except per share amounts).
 
 
2010
Operating revenues
 
$
7,931

Net loss attributable to Calpine
 
$
(83
)
Basic loss per common share attributable to Calpine
 
$
(0.17
)
Diluted loss per common share attributable to Calpine
 
$
(0.17
)
The table below presents the components of our discontinued operations for the period presented (in millions):
 
 
2010
Operating revenues
 
$
92

Gain on disposal of discontinued operations
 
209

Income from discontinued operations before taxes
 
43

Less: Income tax expense
 
59

Discontinued operations, net of tax
 
$
193

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, 2012 and 2011, the components of property, plant and equipment, are stated at cost less accumulated depreciation as follows (in millions):
 
2012
 
2011
 
Depreciable Lives
Buildings, machinery and equipment
$
14,774

 
$
15,074

 
3 – 47 Years
Geothermal properties
1,243

 
1,163

 
13 – 59 Years
Other
142

 
156

 
3 – 47 Years
 
16,159

 
16,393

 
 
Less: Accumulated depreciation
4,390

 
4,158

 
 
 
11,769

 
12,235

 
 
Land
98

 
91

 
 
Construction in progress
1,138

 
693

 
 
Property, plant and equipment, net
$
13,005

 
$
13,019

 
 
Variable Interest Entities and Unconsolidated Investments (Tables)
Aggregated summarized financial data for our unconsolidated subsidiaries is set forth below (in millions):
Condensed Combined Balance Sheets
of Our Unconsolidated Subsidiaries
December 31, 2012 and 2011

 
2012
 
2011
Assets:
 
 
 
Cash and cash equivalents

$
64

 
$
76

Current assets

30

 
37

Property, plant and equipment, net
648

 
656

Other assets
4

 
3

Total assets

$
746

 
$
772

Liabilities:
 
 
 
Current maturities of long-term debt
$
25

 
$
24

Current liabilities

36

 
47

Long-term debt

423

 
438

Long-term derivative liabilities
84

 
85

Total liabilities
568

 
594

Member’s interest

178

 
178

Total liabilities and member’s interest

$
746

 
$
772


Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
For the Years Ended December 31, 2012, 2011 and 2010

 
2012
 
2011
 
2010
Revenues
$
247

 
$
277

 
$
228

Operating expenses
171

 
208

 
183

Income from operations
76

 
69

 
45

Interest expense, net of interest income
27

 
30

 
27

Other (income) expense, net
(2
)
 
2

 

Net income
$
51

 
$
37

 
$
18

At December 31, 2012 and 2011, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of December 31, 2012
 
2012
 
2011
Greenfield LP
50%
 
$
69

 
$
72

Whitby
50%
 
12

 
8

Total investments
 
 
$
81

 
$
80

Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2012, 2011 and 2010, 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 and distributions for the years indicated (in millions):
 
(Income) from Unconsolidated
Investments in Power Plants
 
Distributions
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Greenfield LP
$
(17
)
 
$
(12
)
 
$
(8
)
 
$
22

 
$
2

 
$
6

Whitby
(11
)
 
(9
)
 
(8
)
 
7

 
4

 
5

Total
$
(28
)
 
$
(21
)
 
$
(16
)
 
$
29

 
$
6

 
$
11



Debt (Tables)
Our debt at December 31, 2012 and 2011, was as follows (in millions):
 
2012
 
2011
First Lien Notes(1)
$
5,303

 
$
5,892

First Lien Term Loans(1)
2,463

 
1,646

Project financing, notes payable and other(1)
1,789

 
1,691

CCFC Notes
978

 
972

Capital lease obligations
217

 
224

Total debt
10,750

 
10,425

Less: Current maturities
115

 
104

Debt, net of current portion
$
10,635

 
$
10,321

_____________
(1)
During the fourth quarter of 2012, we redeemed 10% of the aggregate principal amount of our First Lien Notes and repaid project debt with proceeds received from the issuance of our 2019 First Lien Term Loan.
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2012, are as follows (in millions):
 
2013
$
115

2014
188

2015
153

2016
1,162

2017
1,597

Thereafter
7,580

Total debt
10,795

Less: Discount
45

Total
$
10,750

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)
 
2012
 
2011
 
2012
 
2011
2017 First Lien Notes
$
1,080

 
$
1,200

 
7.5
%
 
7.5
%
2019 First Lien Notes
360

 
400

 
8.2

 
8.2

2020 First Lien Notes
983

 
1,092

 
8.1

 
8.1

2021 First Lien Notes
1,800

 
2,000

 
7.7

 
7.7

2023 First Lien Notes
1,080

 
1,200

 
8.0

 
8.0

Total First Lien Notes
$
5,303

 
$
5,892

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
The 2019 First Lien Term Loan carries substantially the same terms as the 2018 First Lien Term Loans and matures on October 9, 2019. The 2019 First Lien Term Loan also contains substantially similar covenants, qualifications, exceptions and limitations as the 2018 First Lien Term Loans and First Lien Notes. We recorded debt extinguishment costs of approximately $18 million associated with the redemption premium, the write-off of unamortized deferred financing costs and debt premium and discount during the fourth quarter of 2012.
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2012
 
2011
 
2012
 
2011
2018 First Lien Term Loans
$
1,630

 
$
1,646

 
4.7
%
 
4.7
%
2019 First Lien Term Loan
833

 

 
4.7

 

Total First Lien Term Loans
$
2,463

 
$
1,646

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
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)
 
2012
 
2011
 
2012
 
2011
Russell City Project Debt due 2023
$
507

 
$
244

 
3.6
%
 
4.1
%
Steamboat due 2017
428

 
437

 
6.8

 
6.6

OMEC due 2019
345

 
355

 
6.8

 
6.8

Los Esteros Project Debt due 2023
209

 
83

 
3.5

 
3.8

Pasadena(2)
160

 
185

 
8.9

 
8.8

Bethpage Energy Center 3 due 2020-2025(3)
93

 
98

 
7.0

 
7.0

Gilroy note payable due 2014
33

 
49

 
10.8

 
10.6

Calpine BRSP due 2014(4)

 
232

 

 
5.7

Other
14

 
8

 

 

Total
$
1,789

 
$
1,691

 
 
 
 
_____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount or premium.
(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)
During the fourth quarter of 2012, we repaid the Calpine BRSP project debt with proceeds received from the issuance of our 2019 First Lien Term Loan.
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, 2012 (in millions):
 
Sale-Leaseback Transactions(1)
 
Capital Lease
 
Total
2013
$
37

 
$
42

 
$
79

2014
25

 
43

 
68

2015
25

 
38

 
63

2016
25

 
41

 
66

2017
17

 
38

 
55

Thereafter
127

 
161

 
288

Total minimum lease payments
256

 
363

 
619

Less: Amount representing interest
96

 
146

 
242

Present value of net minimum lease payments
$
160

 
$
217

 
$
377

____________
(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 table below represents amounts issued under our letter of credit facilities at December 31, 2012 and 2011 (in millions):
 
2012
 
2011
Corporate Revolving Facility
$
243

 
$
440

CDHI
253

 
193

Various project financing facilities
130

 
130

Total
$
626

 
$
763

The following table details the fair values and carrying values of our debt instruments at December 31, 2012 and 2011 (in millions):
 
2012
 
2011
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
5,863

 
$
5,303

 
$
6,219

 
$
5,892

First Lien Term Loans
2,489

 
2,463

 
1,615

 
1,646

Project financing, notes payable and other(1)
1,599

 
1,629

 
1,467

 
1,504

CCFC Notes
1,075

 
978

 
1,070

 
972

Total
$
11,026

 
$
10,373

 
$
10,371

 
$
10,014

____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
Assets and Liabilities with Recurring Fair Value Measurements (Tables)
The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2012:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
December 31, 2012
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
11

 
Discounted cash flow
 
Market price (per MWh)
 
$23.75 — $53.82/MWh
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. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2012
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,502

 
$

 
$

 
$
1,502

Margin deposits
196

 

 

 
196

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
385

 

 

 
385

Commodity forward contracts(2)

 
24

 
24

 
48

Interest rate swaps

 
4

 

 
4

Total assets
$
2,083

 
$
28

 
$
24

 
$
2,135

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
11

 
$

 
$

 
$
11

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
424

 

 

 
424

Commodity forward contracts(2)

 
18

 
8

 
26

Interest rate swaps

 
200

 

 
200

Total liabilities
$
435

 
$
218

 
$
8

 
$
661

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

 
$

 
$

 
$
1,415

Margin deposits
140

 

 

 
140

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

 

 

 
1,043

Commodity forward contracts(2)

 
74

 
37

 
111

Interest rate swaps

 
10

 

 
10

Total assets
$
2,598

 
$
84

 
$
37

 
$
2,719

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

 
$

 
$

 
$
34

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
899

 

 

 
899

Commodity forward contracts(2)

 
184

 
20

 
204

Interest rate swaps

 
320

 

 
320

Total liabilities
$
933

 
$
504

 
$
20

 
$
1,457

___________
(1)
As of December 31, 2012 and 2011, we had cash equivalents of $1,274 million and $1,249 million included in cash and cash equivalents and $228 million and $166 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the years ended December 31, 2012, 2011 and 2010 (in millions):
 
2012
 
2011
 
2010
Balance, beginning of period
$
17

 
$
30

 
$
38

Realized and unrealized gains (losses):
 
 
 
 
 
Included in net income:
 
 
 
 
 
Included in operating revenues(1)
8

 
5

 
7

Included in fuel and purchased energy expense(2)

 

 

Included in OCI

 
2

 
2

Purchases, issuances and settlements:
 
 
 
 
 
Purchases
3

 

 

Issuances
(1
)
 

 

Settlements
(11
)
 
(18
)
 
(20
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
Transfers into level 3(4)

 
(2
)
 

Transfers out of level 3(5)

 

 
3

Balance, end of period
$
16

 
$
17

 
$
30

Change in unrealized gains relating to instruments still held at end of period
$
8

 
$
5

 
$
7

___________
(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, 2012, 2011 and 2010.
(4)
There were no significant transfers into level 3 for the years ended December 31, 2012 and 2010. 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.
(5)
We had no significant transfers out of level 3 for the years ended December 31, 2012 and 2011. There were $3 million in losses transferred out of level 3 into level 2 for the year ended December 31, 2010 due to changes in market liquidity in various power markets.
Derivative Instruments (Tables)
As of December 31, 2012 and 2011, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
2012
 
2011
Power (MWh)
 
(16
)
 
(21
)
Natural gas (MMBtu)
 
66

 
(200
)
Interest rate swaps(1)
 
$
1,602

 
$
5,639

____________
(1)
Approximately $4.1 billion at December 31, 2011 was related to hedges of our First Lien Credit Facility’s variable rate debt that was converted to fixed rate debt. On March 26, 2012, we terminated the interest rate swaps formerly hedging our First Lien Credit Facility
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, 2012 and 2011 (in millions):
 
December 31, 2012
  
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$

 
$
339

 
$
339

Long-term derivative assets
4

 
94

 
98

Total derivative assets
$
4

 
$
433

 
$
437

 
 
 
 
 
 
Current derivative liabilities
$
40

 
$
317

 
$
357

Long-term derivative liabilities
160

 
133

 
293

Total derivative liabilities
$
200

 
$
450

 
$
650

Net derivative assets (liabilities)
$
(196
)
 
$
(17
)
 
$
(213
)

 
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, 2012
 
December 31, 2011
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments(1):
 
 
 
 
 
 
 
Interest rate swaps
$
4

 
$
184

 
$
10

 
$
149

Commodity instruments

 

 
51

 
18

Total derivatives designated as cash flow hedging instruments
$
4

 
$
184

 
$
61

 
$
167

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$

 
$
16

 
$

 
$
171

Commodity instruments
433

 
450

 
1,103

 
1,085

Total derivatives not designated as hedging instruments
$
433

 
$
466

 
$
1,103

 
$
1,256

Total derivatives
$
437

 
$
650

 
$
1,164

 
$
1,423


____________
(1)
Includes accumulated fair value of derivative instruments as of the date hedge accounting was discontinued, net of amortized fair value for settlement periods which have transpired.
The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010 (in millions):
 
2012
 
2011
 
2010
Realized gain (loss)(1)
 
 
 
 
 
Interest rate swaps
$
(157
)
 
$
(193
)
 
$
(31
)
Commodity derivative instruments
387

 
143

 
114

Total realized gain (loss)
$
230

 
$
(50
)
 
$
83

 
 
 
 
 
 
Unrealized gain (loss)(2)
 
 
 
 
 
Interest rate swaps
$
154

 
$
55

 
$
(199
)
Commodity derivative instruments
(82
)
 
(25
)
 
143

Total unrealized gain (loss)
$
72

 
$
30

 
$
(56
)
Total mark-to-market activity, net
$
302

 
$
(20
)
 
$
27

___________
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
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 earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
2012
 
2011
 
2010
Realized and unrealized gain (loss)
 
 
 
 
 
Derivatives contracts included in operating revenues
$
187

 
$
(20
)
 
$
(19
)
Derivatives contracts included in fuel and purchased energy expense
118

 
138

 
276

Interest rate swaps included in interest expense
11

 
7

 
(7
)
Loss on interest rate derivatives
(14
)
 
(145
)
 
(223
)
Total mark-to-market activity, net
$
302

 
$
(20
)
 
$
27

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, 2012 and 2011 (in millions):
 
 
Gains (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(1)
 
Gain (Loss) Reclassified from
AOCI into Income (Ineffective
Portion)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Interest rate swaps
$
(43
)
 
$
(23
)
 
$
(32
)
(2) 
$
(138
)
(2) 
$

 
$
(1
)
Commodity derivative instruments
(38
)
 
(71
)
 
52

(3) 
163

(3) 
2

 
(2
)
Total
$
(81
)
 
$
(94
)
 
$
20

 
$
25

  
$
2

 
$
(3
)
____________
(1)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $242 million and $172 million at December 31, 2012 and 2011, respectively.
(2)
Reclassification of losses from OCI to earnings consisted of $32 million from the reclassification of interest rate contracts due to settlement for each of the years ended December 31, 2012 and 2011, $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 for the year ended December 31, 2011.
(3)
Included in Commodity revenue and Commodity expense on our Consolidated Statements of Operations.
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, 2012 and 2011 (in millions):
 
2012
 
2011
Margin deposits(1)
$
196

 
$
140

Natural gas and power prepayments
35

 
42

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
231

 
$
182

 
 
 
 
Letters of credit issued
$
484

 
$
581

First priority liens under power and natural gas agreements
14

 
1

First priority liens under interest rate swap agreements
206

 
318

Total letters of credit and first priority liens with our counterparties
$
704

 
$
900

 
 
 
 
Margin deposits held by us posted by our counterparties(1)(3)
$
11

 
$
34

Letters of credit posted with us by our counterparties
1

 

Total margin deposits and letters of credit posted with us by our counterparties
$
12

 
$
34

___________
(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, 2012 and 2011, $211 million and $162 million, respectively, were included in margin deposits and other prepaid expense and $20 million and $20 million, respectively, were included in other assets on our Consolidated Balance Sheets.
(3)
Included in other current liabilities on our Consolidated Balance Sheets.
Income Taxes Income Taxes (Tables)
The jurisdictional components of income (loss) from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2012, 2011 and 2010, are as follows (in millions):
 
2012
 
2011
 
2010
U.S.
$
194

 
$
(232
)
 
$
(226
)
International
24

 
20

 
(4
)
Total
$
218

 
$
(212
)
 
$
(230
)
The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2012, 2011 and 2010, consisted of the following (in millions):
 
2012
 
2011
 
2010
 
Current:
 
 
 
 
 
 
Federal
$
(12
)
 
$
(16
)
 
$
(1
)
 
State
16

 
12

 
10

 
Foreign
14

 
3

 
3

 
Total current
18

 
(1
)
 
12

 
Deferred:
 
 
 
 
 
 
Federal
11

 
(33
)
 
(70
)
 
State
(5
)
 
9

 

 
Foreign
(5
)
 
3

 
(10
)
 
Total deferred
1

 
(21
)
 
(80
)
 
Total income tax expense (benefit)
$
19

 
$
(22
)
 
$
(68
)
(1 
) 
_________
(1)
Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI.
A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2012, 2011 and 2010, is as follows:
 
2012
 
2011
 
2010
Federal statutory tax expense (benefit) rate
35.0
 %
 
(35.0
)%
 
(35.0
)%
State tax expense, net of federal benefit
3.2

 
6.5

 
2.8

Depletion in excess of basis
(0.2
)
 

 
(1.3
)
Preferred interest expense
2.0

 
0.4

 
0.5

Federal refunds
(4.7
)
 

 

Valuation allowances against future tax benefits
(32.3
)
 
56.7

 
33.6

Valuation allowances related to reconsolidation of CCFC

 
(36.0
)
 

Valuation allowances related to foreign taxes
(8.2
)
 

 

Foreign taxes
3.7

 
(0.9
)
 
9.9

Non-deductible reorganization items
0.1

 
0.5

 
0.3

Intraperiod allocation
4.6

 
19.9

 
(40.1
)
Bankruptcy settlement

 
(15.7
)
 

Change in unrecognized tax benefits
5.1

 
(6.6
)
 
0.6

Permanent differences and other items
0.4

 
(0.2
)
 
(0.9
)
Effective income tax expense (benefit) rate
8.7
 %
 
(10.4
)%
 
(29.6
)%
The components of the deferred income taxes as of December 31, 2012 and 2011, are as follows (in millions):
 
2012
 
2011
Deferred tax assets:
 
 
 
NOL and credit carryforwards
$
3,073

 
$
3,290

Taxes related to risk management activities and derivatives
90

 
58

Reorganization items and impairments
315

 
318

Foreign capital losses
25

 
24

Other differences
60

 
26

Deferred tax assets before valuation allowance
3,563

 
3,716

Valuation allowance
(2,222
)
 
(2,336
)
Total deferred tax assets
1,341

 
1,380

Deferred tax liabilities: property, plant and equipment
(1,316
)
 
(1,364
)
Net deferred tax asset
25

 
16

Less: Current portion deferred tax liability
(3
)
 
(2
)
Less: Non-current deferred tax asset
28

 
18

Deferred income tax liability, non-current
$

 
$

The following table details the effects of our intraperiod tax allocations for the years ended December 31, 2012, 2011 and 2010 (in millions).
 
2012
 
2011
 
2010
Intraperiod tax allocation expense (benefit) included in continuing operations
$
9

 
$
42

 
$
(86
)
Intraperiod tax allocation expense included in discountinued operations
$

 
$

 
$
59

Intraperiod tax allocation expense (benefit) included in OCI
$
(9
)
 
$
(45
)
 
$
27

A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2012, 2011 and 2010, is as follows (in millions):
 
2012
 
2011
 
2010
Balance, beginning of period
$
(74
)
 
$
(88
)
 
$
(98
)
Increases related to prior year tax positions
(19
)
 

 
(1
)
Decreases related to prior year tax positions
1

 
1

 
11

Decrease related to lapse of statute of limitations

 
13

 

Balance, end of period
$
(92
)
 
$
(74
)
 
$
(88
)
Earnings (Loss) per Share (Tables)
Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the years ended December 31, 2012, 2011 and 2010, are as follows (shares in thousands):
 
2012
 
2011
 
2010
Diluted weighted average shares calculation:
 
 
 
 
 
Weighted average shares outstanding (basic)
467,752

 
485,381

 
486,044

Share-based awards
3,591

 

 
1,250

Weighted average shares outstanding (diluted)
471,343

 
485,381

 
487,294

We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2012, 2011 and 2010, because they were anti-dilutive (shares in thousands):
 
2012
 
2011
 
2010
Share-based awards
10,302

 
15,260

 
14,883

Stock-Based Compensation (Tables)
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2012, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2011
17,665,902

 
$
17.32

 
4.8
 
$
26

Granted
898,115

 
$
15.35

 
 
 
 
Exercised
348,500

 
$
14.94

 
 
 
 
Forfeited
187,716

 
$
13.42

 
 
 
 
Expired
165,300

 
$
17.77

 
 
 
 
Outstanding — December 31, 2012
17,862,501

 
$
17.30

 
4.0
 
$
42

Exercisable — December 31, 2012
10,251,149

 
$
19.16

 
3.6
 
$
12

Vested and expected to vest – December 31, 2012
17,588,775

 
$
17.34

 
3.9
 
$
41

Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
2012
 
2011
 
2010
 
Expected term (in years)(1)
6.5

 
6.5

 
4.0 – 6.5

 
Risk-free interest rate(2)
1.2 – 1.6

%
1.7 – 3.2

%
1.3 – 3.3

%
Expected volatility(3)
27.0 – 30.5

%
31.2 – 44.9

%
31.4 – 37.6

%
Dividend yield(4)

 

 

 
Weighted average grant-date fair value (per option)
$
5.18

 
$
5.49

 
$
1.98

 
___________
(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
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended December 31, 2012, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2011
3,510,358

 
$
12.10

Granted
1,991,894

 
$
15.97

Forfeited
297,166

 
$
13.70

Vested
1,071,049

 
$
10.17

Nonvested — December 31, 2012
4,134,037

 
$
14.33

Capital Structure (Tables)
Schedule of Common Stock Activity
The table below summarizes our common stock activity for the years ended December 31, 2012, 2011 and 2010.
 
Shares
Issued
 
Shares
Held in
Treasury
 
Shares
Held in
Reserve
 
Total
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

Shares issued under Calpine Equity Incentive Plans
2,026,285

 
(284,376
)
 

 
1,741,909

Share repurchase program

 
(26,436,677
)
 

 
(26,436,677
)
Balance, December 31, 2012
492,495,100

 
(35,446,130
)
 

 
457,048,970

Commitments and Contingencies (Tables)
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements related to power plants under construction, at December 31, 2012, are as follows (in millions):
2013
$
548

2014
446

2015
455

2016
397

2017
359

Thereafter
2,078

Total
$
4,283

 
 
Future minimum lease payments under these leases are as follows (in millions):
 
Initial
Year
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
Total
Land and other operating leases
various
 
$
14

 
$
14

 
$
14

 
$
15

 
$
15

 
$
228

 
$
300

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
3

 
$

 
$

 
$

 
$

 
$
10

KIAC
2000
 
24

 
24

 
23

 
22

 
22

 
52

 
167

Total power plant leases
 
 
$
31

 
$
27

 
$
23

 
$
22

 
$
22

 
$
52

 
$
177

Total leases
 
 
$
45

 
$
41

 
$
37

 
$
37

 
$
37

 
$
280

 
$
477

Future minimum lease payments under these leases are as follows (in millions):
2013
$
12

2014
12

2015
12

2016
12

2017
12

Thereafter
31

Total
$
91

At December 31, 2012, 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
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
Total
Guarantee of subsidiary debt(1)
 
$
47

 
$
36

 
$
37

 
$
36

 
$
26

 
$
209

 
$
391

Standby letters of credit(2)(4)
 
536

 
41

 

 

 
19

 
30

 
626

Surety bonds(3)(4)(5)
 

 

 

 

 

 
4

 
4

 Guarantee of subsidiary operating lease payments(4)
 
7

 
3

 

 

 

 

 
10

Total
 
$
590

 
$
80

 
$
37

 
$
36

 
$
45

 
$
243

 
$
1,031

____________
(1)
Represents Calpine Corporation guarantees of certain 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, 2012, $3 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, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,668

 
$
1,857

 
$
1,280

 
$
673

 
$

 
$
5,478

Intersegment revenues
10

 
61

 
14

 
80

 
(165
)
 

Total operating revenues
$
1,678

 
$
1,918

 
$
1,294

 
$
753

 
$
(165
)
 
$
5,478

Commodity Margin (1)(2)
$
994

 
$
570

 
$
729

 
$
245

 
$

 
$
2,538

Add: Unrealized mark-to-market commodity activity, net and other(3)
(93
)
 
87

 
(14
)
 
(33
)
 
(31
)
 
(84
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
368

 
247

 
206

 
131

 
(30
)
 
922

Depreciation and amortization expense
203

 
142

 
134

 
85

 
(2
)
 
562

Sales, general and other administrative expense
36

 
47

 
28

 
29

 

 
140

Other operating expenses
42

 
5

 
29

 
5

 
(3
)
 
78

(Gain) on sale of assets, net

 

 
(7
)
 
(215
)
 

 
(222
)
(Income) from unconsolidated investments in power plants

 

 
(28
)
 

 

 
(28
)
Income from operations
252

 
216

 
353

 
177

 
4

 
1,002

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
725

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
14

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
45

Income before income taxes and discontinued operations
 
 
 
 
 
 
 
 
 
 
$
218


 
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)(2)
$
1,061

 
$
469

 
$
704

 
$
240

 
$

 
$
2,474

Add: Unrealized mark-to-market commodity activity, net and other(3)
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
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)(2)
$
1,080

 
$
504

 
$
535

 
$
272

 
$

 
$
2,391

Add: Unrealized mark-to-market commodity activity, net and other
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
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
)
__________
(1)
Our North segment includes Commodity Margin related to Riverside Energy Center, LLC of $73 million , $70 million and $73 million for the years ended December 31, 2012, 2011 and 2010, respectively.
(2)
Our Southeast segment includes Commodity Margin related to Broad River of $52 million, $51 million and $55 million for the years ended December 31, 2012, 2011 and 2010, respectively.
(3)
Includes $1 million and $12 million of lease levelization and $14 million and $8 million of amortization expense for the years ended December 31, 2012 and 2011, respectively, related to contracts that became effective in 2011.
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)
2012
 
 
 
 
 
 
 
Operating revenues
$
1,367

 
$
1,996

 
$
879

 
$
1,236

Income (loss) from operations
$
295

 
$
705

 
$
(193
)
 
$
195

Net income (loss) attributable to Calpine
$
100

 
$
437

 
$
(329
)
 
$
(9
)
Net income (loss) per common share attributable to Calpine — Basic
$
0.22

 
$
0.95

 
$
(0.69
)
 
$
(0.02
)
Net income (loss) per common share attributable to Calpine — Diluted
$
0.22

 
$
0.94

 
$
(0.69
)
 
$
(0.02
)
 
 
 
 
 
 
 
 
2011
 
 
 
 
 
 
 
Operating revenues
$
1,459

 
$
2,209

 
$
1,633

 
$
1,499

Income from operations
$
196

 
$
403

 
$
183

 
$
18

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

 
$
(70
)
 
$
(297
)
Net income (loss) per common share attributable to Calpine — Basic
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Net income (loss) per common share attributable to Calpine — Diluted
$
(0.03
)
 
$
0.39

 
$
(0.14
)
 
$
(0.61
)
Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Prior Period Reclassification Adjustment
 
$ 10 
$ 9 
Held-to-maturity Securities, Restricted
25 
25 
 
Current
193 
139 
 
Non-current
60 
55 
 
Total
253 
194 
 
Prior Period Adjustment [Abstract]
 
 
 
Cash and cash equivalents subject to project finance facilities and lease agreements
131 
306 
 
Inventory
301 
294 
 
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
116 
Asset retirement obligations
38 
27 
 
Freestone Energy Center [Member]
 
 
 
Jointly Owned Plants [Abstract]
 
 
 
Jointly Owned Utility Plant, Proportionate Ownership Share
75.00% 
 
 
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service
392 
 
 
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation
(124)
 
 
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress
 
 
Hidalgo Energy Center [Member]
 
 
 
Jointly Owned Plants [Abstract]
 
 
 
Jointly Owned Utility Plant, Proportionate Ownership Share
78.50% 
 
 
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service
252 
 
 
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation
(86)
 
 
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress
 
 
Debt Service
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
11 
11 
 
Non-current
41 
42 
 
Total
52 
53 
 
Construction Major Maintenance
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
32 
33 
 
Non-current
14 
10 
 
Total
46 
43 
 
Security Project Insurance
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
101 
79 
 
Non-current
 
Total
104 
79 
 
Other
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
Current
49 
16 
 
Non-current
 
Total
51 
19 
 
Greenfield [Member]
 
 
 
Prior Period Adjustment [Abstract]
 
 
 
Ownership percentage in equity method investment
50.00% 
 
 
Whitby [Member]
 
 
 
Prior Period Adjustment [Abstract]
 
 
 
Ownership percentage in equity method investment
50.00% 
 
 
Two Development Projects [Member]
 
 
 
Prior Period 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, 2012
Summary of Significant Accounting Policies [Abstract]
 
Operating Leases, Future Minimum Payments Receivable, Current
$ 548 
Operating Leases, Future Minimum Payments Receivable, in Two Years
446 
Operating Leases, Future Minimum Payments Receivable, in Three Years
455 
Operating Leases, Future Minimum Payments Receivable, in Four Years
397 
Operating Leases, Future Minimum Payments Receivable, in Five Years
359 
Operating Leases, Future Minimum Payments Receivable, Thereafter
2,078 
Operating Leases, Future Minimum Payments Receivable
$ 4,283 
Acquisitions, Divestitures and Discontinued Operations (Conectiv Acquisition) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2010
Business Acquisition [Line Items]
 
Business Acquisition, Pro Forma Revenue
$ 7,931 
Business Acquisition, Pro Forma Net Income (Loss)
$ (83)
Business Acquisition, Pro Forma Earnings Per Share, Basic
$ (0.17)
Business Acquisition, Pro Forma Earnings Per Share, Diluted
$ (0.17)
Acquisitions, Divestitures and Discontinued Operations (Acquisition of Broad River and South Point Leases) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 8, 2010
Business Acquisition [Line Items]
 
Debt Extinguishment Costs Due To Acquisition
$ 30 
Impairment Loss Due To Acquisition
95 
Business Acquisition, Preexisting Relationship, Gain (Loss) Recognized
$ 125 
Acquisitions, Divestitures and Discontinued Operations (Discontinued Operations) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Business Acquisition [Line Items]
 
 
 
Disposal Group, Including Discontinued Operation, Revenue
 
 
$ 92 
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal
 
 
209 
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax
 
 
43 
Discontinued Operation, Tax Effect of Discontinued Operation
59 
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
$ 0 
$ 0 
$ 193 
Acquisitions, Divestitures and Discontinued Operations (Textuals) (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2012
MW
Dec. 31, 2011
MW
Dec. 31, 2010
Dec. 8, 2010
Dec. 31, 2012
Bosque Energy Center [Member]
MW
Dec. 31, 2011
Conectiv [Member]
Mar. 2, 2011
Conectiv [Member]
MW
Jul. 2, 2010
Conectiv [Member]
Dec. 8, 2010
Broad River and South Point [Member]
Dec. 8, 2010
Broad River [Member]
Dec. 8, 2010
South Point [Member]
Dec. 31, 2012
Riverside Energy Center [Member]
MW
Dec. 31, 2012
Broad River Energy Center [Member]
MW
Dec. 27, 2012
Broad River Energy Center [Member]
Dec. 31, 2010
Blue Spruce and Rock Mountain [Member]
Dec. 6, 2010
Blue Spruce and Rock Mountain [Member]
Dec. 31, 2010
Freestone Energy Center [Member]
Dec. 8, 2010
Freestone Energy Center [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undivided Interest Percentage In Power Plant Asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25.00% 
Cash Proceeds From Sale Of Undivided Interest In Power Plant Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 215,000,000 
Business Acquisition, Preexisting Relationship, Gain (Loss) Recognized
 
 
 
125,000,000 
 
 
 
 
125,000,000 
 
 
 
 
 
 
 
 
 
Business Acquisition, Purchase Price Allocation, Notes Payable and Long-term Debt
 
 
 
 
 
 
 
 
297,000,000 
 
 
 
 
 
 
 
 
 
Variable Interest Entity, Financial or Other Support, Amount
20,000,000 
87,000,000 
46,000,000 
 
 
110,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Power generation capacity
8,255 
11,391 
 
 
800 
 
4,491 
 
 
 
 
603 
847 
 
 
 
 
 
Business Acquisition, Purchase Price Allocation, Assets Acquired
 
 
 
 
432,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of Power Plants Acquired
 
 
 
 
 
 
 
18 
 
 
 
 
 
 
 
 
 
 
Block one power generation capacity
 
 
 
 
250 
 
 
 
 
 
 
 
 
 
 
 
 
 
Block two power generation capacity
 
 
 
 
550 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Cost of Acquired Entity, Purchase Price
 
 
 
 
 
 
 
1,640,000,000 
 
 
 
 
 
 
 
 
 
 
Business Acquisition, Cost of Acquired Entity, Cash Paid
 
 
 
 
 
 
 
 
40,000,000 
 
 
 
 
 
 
 
 
 
Business Acquisition, Purchase Price Allocation, Liabilities Assumed
 
 
 
 
 
 
 
 
85,000,000 
 
 
 
 
 
 
 
 
 
Debt Eliminated In Acquisition
 
 
 
 
 
 
 
 
212,000,000 
 
 
 
 
 
 
 
 
 
Debt Extinguishment Costs Due To Acquisition
 
 
 
30,000,000 
 
 
 
 
 
30,000,000 
 
 
 
 
 
 
 
 
Impairment Loss Due To Acquisition
 
 
 
95,000,000 
 
 
 
 
 
 
95,000,000 
 
 
 
 
 
 
 
Proceeds from Sale of Productive Assets
 
 
 
 
 
 
 
 
 
 
 
402,000,000 
423,000,000 
 
739,000,000 
 
 
 
Gain (Loss) on Disposition of Assets
222,000,000 
119,000,000 
 
 
 
 
 
 
 
 
7,000,000 
215,000,000 
 
 
 
119,000,000 
 
Ownership percentage before divestiture of business
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
100.00% 
 
 
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal
 
 
$ 209,000,000 
 
 
 
 
 
 
 
 
 
 
 
$ 209,000,000 
 
 
 
Property, Plant and Equipment, Net (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Property, Plant and Equipment [Line Items]
 
 
 
Depreciation
$ 557 
$ 560 
$ 568 
Buildings, machinery and equipment
14,774 
15,074 
 
Geothermal properties
1,243 
1,163 
 
Other
142 
156 
 
Property, Plant and Equipment, Gross
16,159 
16,393 
 
Less: Accumulated depreciation
4,390 
4,158 
 
Property, Plant and Equipment, Gross, Less Accumulated Depreciation
11,769 
12,235 
 
Land
98 
91 
 
Construction in progress
1,138 
693 
 
Property, plant and equipment, net
13,005 
13,019 
 
Interest Costs, Capitalized During Period
$ 38 
$ 24 
$ 15 
Building, Machinery and Equipment, Gross [Member] |
Minimum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
P3Y 
 
 
Building, Machinery and Equipment, Gross [Member] |
Maximum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
P47Y 
 
 
Geothermal Properties, Gross [Member] |
Minimum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
P13Y 
 
 
Geothermal Properties, Gross [Member] |
Maximum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
P59Y 
 
 
Property, Plant and Equipment, Other Types [Member] |
Minimum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
P3Y 
 
 
Property, Plant and Equipment, Other Types [Member] |
Maximum [Member]
 
 
 
Property, Plant and Equipment [Line Items]
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
P47Y 
 
 
Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
$ 81 
$ 80 
Greenfield [Member]
 
 
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
69 
72 
Equity Method Investment, Ownership Percentage
50.00% 
 
Whitby [Member]
 
 
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
$ 12 
$ 8 
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, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) from unconsolidated investments in power plants
$ (28)
$ (21)
$ (16)
Return on investment in unconsolidated subsidiaries
29 
11 
Greenfield [Member]
 
 
 
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) from unconsolidated investments in power plants
(17)
(12)
(8)
Return on investment in unconsolidated subsidiaries
22 
Whitby [Member]
 
 
 
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) from unconsolidated investments in power plants
(11)
(9)
(8)
Return on investment in unconsolidated subsidiaries
$ 7 
$ 4 
$ 5 
Variable Interest Entities and Unconsolidated Investments (Equity Method Investment Summarized Financial Information) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Equity Method Investment, Summarized Financial Information, Assets [Abstract]
 
 
 
Equity Method Investment Summarized Financial Information Cash and Cash Equivalents
$ 64 
$ 76 
 
Equity Method Investment, Summarized Financial Information, Current Assets
30 
37 
 
Equity Method Investment, Summarized Financial Information, Property, Plant and Equipment, net
648 
656 
 
Equity Method Investment, Summarized Financial Information, Noncurrent Assets
 
Equity Method Investment, Summarized Financial Information, Assets
746 
772 
 
Equity Method Investment, Summarized Financial Information, Liabilities [Abstract]
 
 
 
Equity Method Investment, Summarized Financial Information, Current Maturities of Long-term Debt
25 
24 
 
Equity Method Investment, Summarized Financial Information, Current Liabilities
36 
47 
 
Equity Method Investment, Summarized Financial Information, Long-Term Debt
423 
438 
 
Equity Method Investment, Summarized Financial Information, Long-term Derivative Liabilities
84 
85 
 
Equity Method Investment, Summarized Financial Information, Liabilities
568 
594 
 
Equity Method Investment Summarized Financial Information, Equity [Abstract]
 
 
 
Equity Method Investment Summarized Financial Information, Equity
178 
178 
 
Equity Method Investment, Summarized Financial Information, Liabilities and Equity
746 
772 
 
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) [Abstract]
 
 
 
Equity Method Investment, Summarized Financial Information, Revenue
247 
277 
228 
Equity Method Investment, Summarized Financial Information, Cost of Sales
171 
208 
183 
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)
76 
69 
45 
Equity Method Investment Summarized Financial Information Interest (Income) Expense
27 
30 
27 
Equity Method Investment Summarized Financial Information Other (Income) Expense Net
(2)
Equity Method Investment, Summarized Financial Information, Net Income (Loss)
$ 51 
$ 37 
$ 18 
Variable Interest Entities and Unconsolidated Investments (VIE Textuals) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
MW
Dec. 31, 2011
MW
Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]
 
 
 
Power generation capacity
8,255 
11,391 
 
Variable Interest Entity, Financial or Other Support, Amount
$ 20 
$ 87 
$ 46 
Equity Method Investment, Summarized Financial Information, Debt
448 
462 
 
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt
224 
231 
 
OMEC [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Power generation capacity
608 
 
 
Russell City Energy [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Minority Interest Ownership Percentage By Noncontrolling Third Party Owners
25.00% 
 
 
Equity Method Investment, Ownership Percentage
75.00% 
 
 
Inland Empire Energy Center [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Power generation capacity
775 
 
 
Put Option Exercise Period
2,025 
 
 
Minimum [Member] |
Inland Empire Energy Center [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Call Option Exercise Period
2,017 
 
 
Maximum [Member] |
Inland Empire Energy Center [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Call Option Exercise Period
2,024 
 
 
Greenfield [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Power generation capacity
1,038 
 
 
Equity Method Investment, Ownership Percentage
50.00% 
 
 
Equity Method Investment, Summarized Financial Information, Term Loan Period
18 years 
 
 
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]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Power generation capacity
50 
 
 
Equity Method Investment, Ownership Percentage
50.00% 
 
 
NDH [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Variable Interest Entity, Financial or Other Support, Amount
 
 
540 
York Energy Center [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Variable Interest Entity, Financial or Other Support, Amount
 
 
$ 110 
Debt (Debt) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,750 
$ 10,425 
Debt, Current
115 
104 
Debt, net of current portion
10,635 
10,321 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
5,303 1
5,892 1
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,789 1
1,691 1
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,463 1
1,646 1
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
978 
972 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 217 
$ 224 
Debt (Annual Debt Marturities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Long-term Debt, Fiscal Year Maturity [Abstract]
 
 
2013
$ 115 
 
2014
188 
 
2015
153 
 
2016
1,162 
 
2017
1,597 
 
Thereafter
7,580 
 
Total debt, gross
10,795 
 
Less: Discount
45 
 
Long-term Debt
$ 10,750 
$ 10,425 
Debt Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,750 
$ 10,425 
First Lien Notes 2017 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
7.50% 1
7.50% 1
Long-term Debt
1,080 
1,200 
First Lien Notes 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
8.20% 1
8.20% 1
Long-term Debt
360 
400 
First Lien Notes 2020 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
8.10% 1
8.10% 1
Long-term Debt
983 
1,092 
First Lien Notes 2021 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
7.70% 1
7.70% 1
Long-term Debt
1,800 
2,000 
First Lien Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
8.00% 1
8.00% 1
Long-term Debt
1,080 
1,200 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 5,303 2
$ 5,892 2
Debt Debt (First Lien Term Loans) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,750 
$ 10,425 
First Lien Term Loans 2018 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,630 
1,646 
Debt Instrument, Interest Rate, Effective Percentage
4.70% 1
4.70% 1
First Lien Term Loan 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
833 
Debt Instrument, Interest Rate, Effective Percentage
4.70% 1
0.00% 1
First Lien Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 2,463 
$ 1,646 
Debt (Project Financing, Notes Payable and Others) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,750 
$ 10,425 
Steamboat [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
507 
244 
Debt Instrument, Interest Rate, Effective Percentage
3.60% 1
4.10% 1
OMEC [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
428 
437 
Debt Instrument, Interest Rate, Effective Percentage
6.80% 1
6.60% 1
Russell City Project [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
345 
355 
Debt Instrument, Interest Rate, Effective Percentage
6.80% 1
6.80% 1
BRSP [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
209 
83 
Debt Instrument, Interest Rate, Effective Percentage
3.50% 1
3.80% 1
Pasadena [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
160 2
185 2
Debt Instrument, Interest Rate, Effective Percentage
8.90% 1 2
8.80% 1 2
Bethpage [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
93 3
98 3
Debt Instrument, Interest Rate, Effective Percentage
7.00% 1 3
7.00% 1 3
Los Esteros Project [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
33 
49 
Debt Instrument, Interest Rate, Effective Percentage
10.80% 1
10.60% 1
Gilroy note payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
4
232 4
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1 4
5.70% 1 4
Other Credit Derivatives [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
14 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
0.00% 1
Project Financing Total [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 1,789 
$ 1,691 
Debt (Capital Lease Obligations) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Minimum Lease Payments, Sale Leaseback Transactions, Fiscal Year Maturity [Abstract]
 
Minimum Lease Payments, Sale Leaseback Transactions, within One Year
$ 37 1
Minimum Lease Payments, Sale Leaseback Transactions, within Two Years
25 1
Minimum Lease Payments, Sale Leaseback Transactions, within Three Years
25 1
Minimum Lease Payments, Sale Leaseback Transactions, within Four Years
25 1
Minimum Lease Payments, Sale Leaseback Transactions, within Five Years
17 1
Minimum Lease Payments, Sale Leaseback Transactions, Thereafter
127 1
Minimum Lease Payments, Sale Leaseback Transactions
256 1
Interest Portion of Minimum Lease Payments, Sale Leaseback Transactions
96 1
Present Value of Future Minimum Lease Payments, Sale Leaseback Transactions
160 1
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
 
Capital Leases, Future Minimum Payments Due, Current
42 
Capital Leases, Future Minimum Payments Due in Two Years
43 
Capital Leases, Future Minimum Payments Due in Three Years
38 
Capital Leases, Future Minimum Payments Due in Four Years
41 
Capital Leases, Future Minimum Payments Due in Five Years
38 
Capital Leases, Future Minimum Payments Due Thereafter
161 
Capital Leases, Future Minimum Payments Due
363 
Capital Leases, Future Minimum Payments, Interest Included in Payments
146 
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments
217 
Total Leases Future Minimum Payments [Abstract]
 
Total Leases, Future Minimum Payments Due, Current
79 
Total Leases, Future Minimum Payments Due in Two Years
68 
Total Leases, Future Minimum Payments Due in Three Years
63 
Total Leases, Future Minimum Payments Due in Four Years
66 
Total Leases, Future Minimum Payments Due in Five Years
55 
Total Leases, Future Minimum Payments Due Thereafter
288 
Total Leases, Future Minimum Payments Due
619 
Total Leases, Future Minimum Payments, Interest Included in Payments
242 
Total Leases, Future Minimum Payments, Present Value of Net Minimum Payments
$ 377 
Debt (Corporate Revolving Facility and other Letters of Credit Facilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Line of Credit Facility [Line Items]
 
 
Line of Credit Facility, Fair Value of Amount Outstanding
$ 626 
$ 763 
Corporate Revolving Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Line of Credit Facility, Fair Value of Amount Outstanding
243 
440 
CDH [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Line of Credit Facility, Fair Value of Amount Outstanding
253 
193 
Various Project Financing Facilities [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Line of Credit Facility, Fair Value of Amount Outstanding
$ 130 
$ 130 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Portion at Fair Value, Fair Value Disclosure [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
$ 5,863 
$ 6,219 
Notes Payable, Other Payables, Disclosure
1,599 1
1,467 1
Loans Payable, Fair Value Disclosure
2,489 
1,615 
Subsidiaries Notes Disclosure
1,075 
1,070 
Debt Excluding Capital Leases
11,026 
10,371 
Carrying (Reported) Amount, Fair Value Disclosure [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
5,303 
5,892 
Notes Payable, Other Payables, Disclosure
1,629 1
1,504 1
Loans Payable, Fair Value Disclosure
2,463 
1,646 
Subsidiaries Notes Disclosure
978 
972 
Debt Excluding Capital Leases
$ 10,373 
$ 10,014 
Debt (Textuals) (Details) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Debt Instrument [Line Items]
 
 
 
Gains (Losses) on Extinguishment of Debt
$ (30,000,000)
$ (94,000,000)
$ (91,000,000)
Maximum Remaining Lease Term
36 
 
 
Lease Assets, Historical Cost
880,000,000 
879,000,000 
 
Lease Assets, Accumulated Depreciation
312,000,000 
318,000,000 
 
2019 First Lien Term Loan [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument Redemption Premium Percentage
10.00% 
 
 
Redemption amount percentage
103.00% 
 
 
Debt Instrument, Face Amount
835,000,000 
 
 
Debt Instrument, Interest Rate, Stated Percentage
4.50% 
 
 
Gains (Losses) on Extinguishment of Debt
18,000,000 
 
 
First Lien Term Loans [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
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% 
 
 
BRSP [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
218,000,000 
 
 
First Lien Notes 2017 [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
7.25% 
 
 
First Lien Notes 2019 [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Interest Rate, Stated Percentage
8.00% 
 
 
CCFC Notes [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
 
 
1,000,000,000 
Debt Instrument, Interest Rate, Stated Percentage
 
 
8.00% 
Number of power plants
 
 
Debt, Weighted Average Interest Rate
 
8.90% 
8.90% 
Corporate Revolving Facility [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Percentage added to Federal Funds Effective Rate to arrive at base rate
0.50% 
 
 
Repayment time for drawings under letters of credit
2 days 
 
 
Excess amount of asset sales requiring mandatory prepayments
3,000,000,000 
 
 
Corporate Revolving Facility [Member] |
Minimum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
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% 
 
 
Corporate Revolving Facility [Member] |
Maximum [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
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% 
 
 
CDHI [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Letter of Credit Total
300,000,000 
 
 
Cash collateralize letters of credit issued
225,000,000 
 
 
Pledged Financial Instruments, Not Separately Reported, Securities for Letter of Credit Facilities
$ 28,000,000 
 
 
One Month [Member] |
Corporate Revolving Facility [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Interest periods for LIBOR rate borrowings
1 month 
 
 
Two Months [Member] |
Corporate Revolving Facility [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Interest periods for LIBOR rate borrowings
2 months 
 
 
Three Months [Member] |
Corporate Revolving Facility [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Interest periods for LIBOR rate borrowings
3 months 
 
 
Six Months [Member] |
Corporate Revolving Facility [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Interest periods for LIBOR rate borrowings
6 months 
 
 
Nine Months [Member] |
Corporate Revolving Facility [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Interest periods for LIBOR rate borrowings
9 months 
 
 
Twelve Months [Member] |
Corporate Revolving Facility [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Interest periods for LIBOR rate borrowings
12 months 
 
 
Assets and Liabilities with Recurring Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 1,502 1
$ 1,415 1
Margin deposits
196 2
140 2
Commodity futures contracts
385 
1,043 
Commodity forward contracts
48 3
111 3
Interest rate swaps
10 
Total assets
2,135 
2,719 
Margin deposits held by us posted by our counterparties
11 2 4
34 2 4
Commodity futures contracts
424 
899 
Commodity forward contracts
26 3
204 3
Interest rate swaps
200 
320 
Total liabilities
661 
1,457 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1,502 1
1,415 1
Margin deposits
196 
140 
Commodity futures contracts
385 
1,043 
Commodity forward contracts
3
3
Interest rate swaps
Total assets
2,083 
2,598 
Margin deposits held by us posted by our counterparties
11 
34 
Commodity futures contracts
424 
899 
Commodity forward contracts
3
3
Interest rate swaps
Total liabilities
435 
933 
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1
1
Margin deposits
Commodity futures contracts
Commodity forward contracts
24 3
74 3
Interest rate swaps
10 
Total assets
28 
84 
Margin deposits held by us posted by our counterparties
Commodity futures contracts
Commodity forward contracts
18 3
184 3
Interest rate swaps
200 
320 
Total liabilities
218 
504 
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1
1
Margin deposits
Commodity futures contracts
Commodity forward contracts
24 3
37 3
Interest rate swaps
Total assets
24 
37 
Margin deposits held by us posted by our counterparties
Commodity futures contracts
Commodity forward contracts
3
20 3
Interest rate swaps
Total liabilities
$ 8 
$ 20 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
Balance, beginning of period
$ 17 
$ 30 
$ 38 
Included in net income:
 
 
 
Included in operating revenues
1
1
1
Included in fuel and purchased energy expense
2
2
2
Included in OCI
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issues
(1)
Purchases, issuances and settlements:
 
 
 
Settlements
(11)
(18)
(20)
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount
Transfers into level 3
3 4
(2)3 4
3 4
Transfers out of level 3
4 5
4 5
Balance, end of period
16 
17 
30 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Change in Unrealized Gain (Loss) Held At Period End
2
2
2
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure
1,274 
1,249 
 
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure
$ 228 
$ 166 
 
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Information about Level 3 Fair Value Measurements (Details)
Dec. 31, 2012
MW
Physical Power [Member]
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
Fair Value Inputs Quantitative Information Power
11,000,000 
Minimum [Member]
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
Fair Value Inputs Quantitative Information Power
23.75 
Maximum [Member]
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
Fair Value Inputs Quantitative Information Power
53.82 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
MMBTU
MW
Dec. 31, 2011
MW
MMBTU
Derivative Instruments [Abstract]
 
 
Nonmonetary Notional Amount of Price Risk Derivatives Power
(16)
(21)
Price Risk Derivatives [Abstract]
 
 
Natural gas (MMBtu)
66 
(200)
Interest rate swaps
$ 1,602 1
$ 5,639 1
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
$ 339 
$ 1,051 
Long-term derivative assets
98 
113 
Total derivative assets
437 
1,164 
Current derivative liabilities
357 
1,144 
Long-term derivative liabilities
293 
279 
Total derivative liabilities
650 
1,423 
Net derivative assets (liabilities)
(213)
(259)
Fair Value of Derivative Assets
437 
1,164 
Fair Value of Derivative Liabilities
650 
1,423 
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
1
61 1
Fair Value of Derivative Liabilities
184 1
167 1
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
433 
1,103 
Fair Value of Derivative Liabilities
466 
1,256 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
Long-term derivative assets
10 
Total derivative assets
10 
Current derivative liabilities
40 
166 
Long-term derivative liabilities
160 
154 
Total derivative liabilities
200 
320 
Net derivative assets (liabilities)
(196)
(310)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
1
10 1
Fair Value of Derivative Liabilities
184 1
149 1
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
Fair Value of Derivative Liabilities
16 
171 
Commodity Option [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
339 
1,051 
Long-term derivative assets
94 
103 
Total derivative assets
433 
1,154 
Current derivative liabilities
317 
978 
Long-term derivative liabilities
133 
125 
Total derivative liabilities
450 
1,103 
Net derivative assets (liabilities)
(17)
51 
Commodity Option [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
1
51 1
Fair Value of Derivative Liabilities
1
18 1
Commodity Option [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
433 
1,103 
Fair Value of Derivative Liabilities
$ 450 
$ 1,085 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gain (Loss) on Sale of Derivatives
$ 230 1
$ (50)1
$ 83 1
Unrealized Gain (Loss) on Derivatives
72 2
30 2
(56)2
Gain (Loss) on Derivative Instruments, Net, Pretax
302 
(20)
27 
Power contracts included in operating revenues
187 
(20)
(19)
Natural gas contracts included in fuel and purchased energy expense
118 
138 
276 
Interest rate swaps included in interest expense
(11)
(7)
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
(14)
(145)
(223)
Interest Rate Swap [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gain (Loss) on Sale of Derivatives
(157)1
(193)1
(31)1
Unrealized Gain (Loss) on Derivatives
154 2
55 2
(199)2
Commodity Option [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gain (Loss) on Sale of Derivatives
387 1
143 1
114 1
Unrealized Gain (Loss) on Derivatives
$ (82)2
$ (25)2
$ 143 2
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
$ (81)
$ (94)
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
20 1
25 1
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
(3)
Interest Rate Swap [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
(43)
(23)
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
(32)1 2
(138)1 2
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
(1)
Commodity Option [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
(38)
(71)
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
52 1 3
163 1 3
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
$ 2 
$ (2)
Derivative Instruments (Textuals) (Details) (USD $)
3 Months Ended 12 Months Ended 3 Months Ended
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Interest Rate Swap [Member]
Dec. 31, 2011
Interest Rate Swap [Member]
Dec. 31, 2010
Interest Rate Swap [Member]
Mar. 31, 2012
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
 
 
 
 
 
 
 
 
Gain (Loss) on Sale of Derivatives
 
$ 230,000,000 1
$ (50,000,000)1
$ 83,000,000 1
$ (157,000,000)1
$ (193,000,000)1
$ (31,000,000)1
 
Derivative Instruments (Textuals) [Abstract]
 
 
 
 
 
 
 
 
Maximum length of time hedging using interest rate derivative instruments
 
11 years 
 
 
 
 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
 
5,000,000 
 
 
 
 
 
 
Collateral Already Posted, Aggregate Fair Value
 
1,000,000 
 
 
 
 
 
 
Additional Collateral, Aggregate Fair Value
 
1,000,000 
 
 
 
 
 
 
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 
 
91,000,000 
206,000,000 
 
 
 
 
Unrealized losses associated with interest rate swap breakage costs
 
32,000,000 
 
 
 
 
 
 
Cumulative cash flow hedge losses remaining in AOCI
 
242,000,000 
172,000,000 
 
 
 
 
 
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months
 
41,000,000 
 
 
 
 
 
 
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 
 
 
 
 
 
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
 
(14,000,000)
(145,000,000)
(223,000,000)
 
 
 
156,000,000 
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Unrealized
 
14,000,000 
 
 
 
 
 
 
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Realized
 
 
142,000,000 
 
 
 
 
 
Unrealized Gain (Loss) on Derivatives
 
72,000,000 2
30,000,000 2
(56,000,000)2
154,000,000 2
55,000,000 2
(199,000,000)2
 
Interest rate swaps included in interest expense
 
$ (11,000,000)
$ (7,000,000)
$ 7,000,000 
 
 
 
 
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Use of Collateral [Abstract]
 
 
Margin deposits
$ 196 1
$ 140 1
Natural gas and power prepayments
35 
42 
Total margin deposits and natural gas and power prepayments with our counterparties
231 2
182 2
Letters of credit issued
484 3
581 3
First priority liens under power and natural gas agreements
14 
First priority liens under interest rate swap agreements
206 
318 
Total letters of credit and first priority liens with our counterparties
704 
900 
Margin deposits held by us posted by our counterparties
11 1 3
34 1 3
Letters of credit posted with us by our counterparties
Total margin deposits and letters of credit posted with us by our counterparties
12 
34 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
20 
20 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
$ 211 
$ 162 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Tax Disclosure [Abstract]
 
 
 
U.S.
$ 194 
$ (232)
$ (226)
International
24 
20 
(4)
Total
$ 218 
$ (212)
$ (230)
Income Taxes (Components of Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Current:
 
 
 
Federal
$ (12)
$ (16)
$ (1)
State
16 
12 
10 
Foreign
14 
Total current
18 
(1)
12 
Deferred:
 
 
 
Federal
11 
(33)
(70)
State
(5)
Foreign
(5)
(10)
Total deferred
(21)
(80)
Total income tax expense (benefit)
$ 19 
$ (22)1
$ (68)
Income Taxes (Effective Income Tax Expense (Benefit) Rate) (Details)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Tax [Line Items]
 
 
 
Federal statutory tax expense (benefit) rate
35.00% 
(35.00%)
(35.00%)
State tax expense (benefit), net of federal benefit
3.20% 
6.50% 
2.80% 
Depletion in excess of basis
(0.20%)
0.00% 
(1.30%)
Effective Income Tax Rate Reconciliation Nondeductible Expense Preferred Interest Expense
2.00% 
0.40% 
0.50% 
Effective Income Tax Rate Reconciliation, Tax Settlements, Domestic
(4.70%)
0.00% 
0.00% 
Valuation allowances
(32.30%)
56.70% 
33.60% 
Effective Income Tax Rate Reconciliation Change In Deferred Tax Assets Valuation Allowance Due To Reconsolidation
0.00% 
(36.00%)
0.00% 
Effective Income Tax Rate Reconciliation Change in Deferred Tax Assets, Valuation Allowance Due to Foreign Taxes
(8.20%)
0.00% 
0.00% 
Foreign taxes
3.70% 
(0.90%)
9.90% 
Non-deductible reorganization items
0.10% 
0.50% 
0.30% 
Intraperiod allocation
4.60% 
19.90% 
(40.10%)
Bankruptcy settlement
0.00% 
(15.70%)
0.00% 
Change in unrecognized tax benefits
5.10% 
(6.60%)
0.60% 
Permanent differences and other items
0.40% 
(0.20%)
(0.90%)
Effective income tax expense (benefit) rate
8.70% 
(10.40%)
(29.60%)
Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Deferred tax assets:
 
 
NOL and credit carryforwards
$ 3,073 
$ 3,290 
Taxes related to risk management activities and derivatives
90 
58 
Reorganization items and impairments
315 
318 
Foreign capital losses
25 
24 
Other differences
60 
26 
Deferred tax assets before valuation allowance
3,563 
3,716 
Valuation allowance
(2,222)
(2,336)
Total deferred tax assets
1,341 
1,380 
Deferred tax liabilities: property, plant and equipment
(1,316)
(1,364)
Net deferred tax asset (liability)
25 
16 
Less: Current portion deferred tax asset (liability)
(3)
(2)
Less: Non-current deferred tax asset
28 
18 
Deferred income tax liability, net of current
$ 0 
$ 0 
Income Taxes (Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Tax Disclosure [Abstract]
 
 
 
Deferred income tax liability, net of current
$ 9 
$ 42 
$ (86)
Discontinued Operation, Tax Effect of Discontinued Operation
59 
Intraperiod tax allocation expense (benefit) included in OCI
$ (9)
$ (45)
$ 27 
Income Taxes (Income Tax Contingencies) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Tax Disclosure [Abstract]
 
 
 
Balance, beginning of period
$ (74)
$ (88)
$ (98)
Increases related to prior year tax positions
(19)
(1)
Decreases related to prior year tax positions
11 
Decrease related to lapse of statute of limitations
13 
Balance, end of period
$ (92)
$ (74)
$ (88)
Income Taxes (Textuals) (Details) (USD $)
3 Months Ended 12 Months Ended
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Intraperiod income tax [Line Items]
 
 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, Domestic
 
$ 7,300,000,000 
 
 
 
Income Tax Expense (Benefit) [Abstract]
 
 
 
 
 
Deferred income tax liability, net of current
 
9,000,000 
42,000,000 
(86,000,000)
 
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
 
92,000,000 
74,000,000 
88,000,000 
98,000,000 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
 
36,000,000 
 
 
 
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward
 
56,000,000 
 
 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
 
24,000,000 
 
 
 
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
 
7,300,000,000 
 
 
 
Operating Loss Carryforwards Available To Offset Future Income
 
7,100,000,000 
 
 
 
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost
 
10,000,000 
 
 
 
Operating Loss Carryforwards Not Limited On Use
 
2,400,000,000 
 
 
 
NOLs expected to expire unutilized
 
 
640,000,000 
 
 
NOLs expected to expire unutilized due to carryforward time constraints
 
117,000,000 
 
 
 
Reduction In State NOLs
 
 
44,000,000 
 
 
Reduction Of State Taxable Income
 
 
24,000,000 
 
 
Valuation allowance
 
2,222,000,000 
2,336,000,000 
 
 
Valuation Allowance, Deferred Tax Asset, Change in Amount
 
(114,000,000)
(50,000,000)
(186,000,000)
 
Tax refund due to foreign dividend income treatment
 
10,000,000 
 
 
 
Tax refund plus accrued interest due to foreign dividend income treatment
 
13,000,000 
 
 
 
Accrued interest on foreign dividend refund
 
3,000,000 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, State and Local
 
4,000,000,000 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, Foreign
 
1,000,000,000 
 
 
 
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound
 
 
 
 
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound
 
28,000,000 
 
 
 
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, 2012
Dec. 31, 2011
Dec. 31, 2010
Earnings (Loss) per Share [Abstract]
 
 
 
Shares Of New, Reorganized Common Stock
485,000,000 
 
 
Diluted weighted average shares calculation:
 
 
 
Weighted average shares outstanding (basic)
467,752,000 
485,381,000 
486,044,000 
Share-based awards
3,591,000 
1,250,000 
Weighted average shares outstanding (in shares)
471,343,000 
485,381,000 
487,294,000 
Items excluded from diluted earnings (loss) per common share
 
 
 
Share-based awards
10,302,000 
15,260,000 
14,883,000 
Stock-Based Compensation (Details) (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value
$ 1,000,000 
$ 0 
$ 0 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
20,000,000 
7,000,000 
4,000,000 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
 
 
 
Options Outstanding, Beginning balance, Number
17,665,902 
 
 
Options Outstanding, Beginning balance, Weighted Average Exercise Price
$ 17.32 
 
 
Options Ouststanding, Beginning balance, Weighted Average Remaining Term (in years)
4 years 0 months 0 days 
4 years 9 months 18 days 
 
Options Outstanding, Beginning balance, Aggregate Intrinsic Value (in $ millions)
26,000,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross
898,115 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price
$ 15.35 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period
348,500 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price
$ 14.94 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period
187,716 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price
$ 13.42 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period
165,300 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price
$ 17.77 
 
 
Options Outstanding, Ending balance, Number
17,862,501 
17,665,902 
 
Options Outstanding, Ending balance, Weighted Average Exercise Price
$ 17.30 
$ 17.32 
 
Options Ouststanding, Ending balance, Weighted Average Remaining Term (in years)
4 years 0 months 0 days 
4 years 9 months 18 days 
 
Options Outstanding, Ending balance, Aggregate Intrinsic Value (in $ millions)
42,000,000 
26,000,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number
10,251,149 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price
$ 19.16 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term
3 years 7 months 6 days 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value
12,000,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number
17,588,775 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price
$ 17.34 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term
3 years 10 months 24 days 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value
41,000,000 
 
 
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 years 6 months 0 days 1
6 years 6 months 0 days 
 
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
$ 5.18 
$ 5.49 
$ 1.98 
Restricted Stock and Stock Unit Activity [Abstract]
 
 
 
Nonvested Restricted Stock, Beginning balance, Number
3,510,358 
 
 
Nonvested Restricted Stock, Beginning balance, Weighted Average Grant Date Fair Value
$ 12.10 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
1,991,894 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 15.97 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
297,166 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period, Weighted Average Grant Date Fair Value
$ 13.70 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
1,071,049 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 10.17 
 
 
Nonvested Restricted Stock, Ending balance, Number
4,134,037 
3,510,358 
 
Nonvested Restricted Stock, Ending balance, Weighted Average Grant Date Fair Value
$ 14.33 
$ 12.10 
 
Disclosure of Compensation Related Costs Share-based Payments (Textuals) [Abstract]
 
 
 
Vesting period for graded and cliff vesting options - minimum
1 year 
 
 
Vesting period for graded and cliff vesting options - maximum
5 years 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Minimum Range
5 years 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Maximum Range
10 years 
 
 
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 year 
 
 
Vest Term of the Second Sub-Grant
2 years 
 
 
Vest Term of the Third Sub-Grant
3 years 
 
 
Grants in Option Grants with Three Year Cliff Vesting
 
 
Vesting term of option grants with three year cliff vesting
3 years 
 
 
Stock-based compensation expense
25,000,000 
24,000,000 
24,000,000 
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options
5,000,000 
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 years 0 months 0 days 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
1.20% 
1.70% 
1.30% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
27.00% 
31.20% 
31.40% 
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, Expected Term
 
 
6 years 6 months 0 days 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
1.60% 
3.20% 
3.30% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
30.50% 
44.90% 
37.60% 
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
6,000,000 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
0 years 9 months 18 days 
 
 
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
25,000,000 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
1 year 3 months 18 days 
 
 
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 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
0 years 4 months 24 days 
 
 
Defined Contribution and Defined Benefit Plans (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Defined Contribution and Defined Benefit Plans [Abstract]
 
 
 
Defined Contribution Plan, Cost Recognized
$ 11 
$ 10 
$ 9 
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
 
 
Grandfathered Pension Liability Employees
 
 
130 
Defined Benefit Plan, Assets for Plan Benefits
12 
10 
 
Pension and Other Postretirement Defined Benefit Plans, Liabilities
21 
18 
 
Defined Benefit Plan, Amounts Recognized in Balance Sheet
 
Defined Benefit Plan, Net Periodic Benefit Cost
Defined Benefit Plan, Net Periodic Benefit Cost Related To Voluntary Retirement Incentive
 
 
Number Of Employees That Accepted The Voluntray Retirement Incentive
 
 
31 
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax
 
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year
 
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year
 
 
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter
$ 1 
 
 
Capital Structure (Details) (USD $)
1 Months Ended 3 Months Ended 12 Months Ended
Feb. 12, 2013
Mar. 31, 2013
Jun. 30, 2012
Sep. 30, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Class of Stock [Line Items]
 
 
 
 
 
 
 
Shares Of New, Reorganized Common Stock
 
 
 
 
485,000,000 
 
 
Common Stock, authorized shares (in shares)
 
 
 
 
(1,400,000,000)
(1,400,000,000)
 
Common Stock, issued shares (in shares)
 
 
 
 
(492,495,100)
(490,468,815)
 
Common Stock, par value (in dollars per share)
 
 
 
 
$ (0.001)
$ (0.001)
 
Common Stock, outstanding shares (in shares)
 
 
 
 
(457,048,970)
(481,743,738)
 
Treasury Stock, Shares (in shares)
 
 
 
 
35,446,130 
8,725,077 
 
Treasury Stock, Value
 
 
 
 
$ 594,000,000 
$ 125,000,000 
 
Stock Repurchase Program, Authorized Amount
 
400,000,000 
600,000,000 
300,000,000 
 
 
 
Treasury Stock, Value, Acquired, Cost Method
 
 
 
 
469,000,000 
120,000,000 
2,000,000 
Treasury Stock Acquired, Average Cost Per Share
$ 16.87 
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
 
Total common shares outstanding, beginning balance
(457,048,970)
(457,048,970)
 
 
(481,743,738)
(488,693,630)
(487,745,299)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
Shares issued under Calpine Equity Incentive Plans
 
 
 
 
1,741,909 
1,187,181 
948,331 
Share repurchase program
(35,568,833)
 
 
 
(26,436,677)
(8,137,073)
 
Total common shares outstanding, ending balance
 
 
 
 
(457,048,970)
(481,743,738)
(488,693,630)
Stock Repurchase Program, Cumulative Authorized Amount
 
 
 
 
$ 1,000,000,000 
 
 
Shares Issued [Member]
 
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
 
Total common shares outstanding, beginning balance
 
 
 
 
(490,468,815)
(444,883,356)
(443,325,827)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
44,258,432 
488,612 
Shares issued under Calpine Equity Incentive Plans
 
 
 
 
2,026,285 
1,327,027 
1,068,917 
Share repurchase program
 
 
 
 
 
Total common shares outstanding, ending balance
 
 
 
 
(492,495,100)
(490,468,815)
(444,883,356)
Shares Held inTreasury [Member]
 
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
 
Total common shares outstanding, beginning balance
 
 
 
 
(8,725,077)
(448,158)
(327,572)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
Shares issued under Calpine Equity Incentive Plans
 
 
 
 
284,376 
139,846 
120,586 
Share repurchase program
 
 
 
 
(26,436,677)
(8,137,073)
 
Total common shares outstanding, ending balance
 
 
 
 
(35,446,130)
(8,725,077)
(448,158)
Shares Held in Reserve [Member]
 
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
 
Total common shares outstanding, beginning balance
 
 
 
 
(44,258,432)
(44,747,044)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
44,258,432 
488,612 
Shares issued under Calpine Equity Incentive Plans
 
 
 
 
Share repurchase program
 
 
 
 
 
Total common shares outstanding, ending balance
 
 
 
 
(44,258,432)
Commitments and Contingencies (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Commitments and Contingencies [Line Items]
 
 
 
Schedule of Guarantor Obligations
 
 
Guarantor Obligations, Current Carrying Value
$ 3 
 
 
Outstanding claims related to guarantees
 
 
Royalty Expense
22 
22 
25 
LTSA [Member]
 
 
 
Unrecorded Unconditional Purchase Obligation
 
 
 
Unrecorded Unconditional Purchase Obligation
68 
 
 
Term of Unrecorded Unconditional Purchase Obligation Lower Limit
P1Y 
 
 
Term of Unrecorded Unconditional Purchase Obligation Upper Limit
P5Y 
 
 
Public Utilities, Inventory, Fuel [Member]
 
 
 
Unrecorded Unconditional Purchase Obligation
 
 
 
Unrecorded Unconditional Purchase Obligation
$ 3,000 
 
 
Term of Unrecorded Unconditional Purchase Obligation Lower Limit
P1Y 
 
 
Term of Unrecorded Unconditional Purchase Obligation Upper Limit
P13Y 
 
 
Term of Unrecorded Unconditional Purchase Obligation Outlier
29 years 
 
 
At December 31, 2012, 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
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
Total
Guarantee of subsidiary debt(1)
 
$
47

 
$
36

 
$
37

 
$
36

 
$
26

 
$
209

 
$
391

Standby letters of credit(2)(4)
 
536

 
41

 

 

 
19

 
30

 
626

Surety bonds(3)(4)(5)
 

 

 

 

 

 
4

 
4

 Guarantee of subsidiary operating lease payments(4)
 
7

 
3

 

 

 

 

 
10

Total
 
$
590

 
$
80

 
$
37

 
$
36

 
$
45

 
$
243

 
$
1,031

____________
(1)
Represents Calpine Corporation guarantees of certain 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, 2012, $3 million of cash collateral is outstanding related to these bonds.
Commitments and Contingencies (Schedules of Future Minimum Rental Payments) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Land and Other Operating Leases [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
$ 300 
 
 
Operating Leases, Future Minimum Payments Due, Current
14 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
14 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
14 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
15 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
15 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
228 
 
 
Greenleaf [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
10 
 
 
KIAC [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
167 
 
 
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
23 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
22 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
22 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
52 
 
 
Total Power Plant Leases [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
177 
 
 
Operating Leases, Future Minimum Payments Due, Current
31 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
27 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
23 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
22 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
22 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
52 
 
 
Operating Leases, Rent Expense, Net
51 
53 
60 
Operting Lease Assets Total [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
477 
 
 
Operating Leases, Future Minimum Payments Due, Current
45 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
41 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
37 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
37 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
37 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
280 
 
 
Office Equipment [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
91 
 
 
Operating Leases, Future Minimum Payments Due, Current
12 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
12 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
12 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
12 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
12 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
31 
 
 
Operating Leases, Rent Expense, Net
12 
13 
12 
Greenleaf [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Guarantee Obligations Balance On First Anniversary
 
 
Guarantee Obligations Balance On Second Anniversary
 
 
Guarantee Obligations Balance On Third Anniversary
 
 
Guarantee Obligations Balance On Fourth Anniversary
 
 
Guarantee Obligations Balance On Fifth Anniversary
 
 
Guarantee Obligations Due After Five Years
$ 0 
 
 
Commitments and Contingencies (Schedule of Guarantor Obligations) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Loans Payable [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
$ 47 1
Guarantee Obligations Balance On Second Anniversary
36 1
Guarantee Obligations Balance On Third Anniversary
37 1
Guarantee Obligations Balance On Fourth Anniversary
36 1
Guarantee Obligations Balance On Fifth Anniversary
26 1
Guarantee Obligations Due After Five Years
209 1
Guarantor Obligations, Maximum Exposure, Undiscounted
391 1
Financial Standby Letter of Credit [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
536 2 3
Guarantee Obligations Balance On Second Anniversary
41 2 3
Guarantee Obligations Balance On Third Anniversary
2 3
Guarantee Obligations Balance On Fourth Anniversary
2 3
Guarantee Obligations Balance On Fifth Anniversary
19 2 3
Guarantee Obligations Due After Five Years
30 2 3
Guarantor Obligations, Maximum Exposure, Undiscounted
626 2 3
Surety Bonds [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
2 4 5
Guarantee Obligations Balance On Second Anniversary
2 4 5
Guarantee Obligations Balance On Third Anniversary
2 4 5
Guarantee Obligations Balance On Fourth Anniversary
2 4 5
Guarantee Obligations Balance On Fifth Anniversary
2 4 5
Guarantee Obligations Due After Five Years
2 4 5
Guarantor Obligations, Maximum Exposure, Undiscounted
2 4 5
Greenleaf [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
Guarantee Obligations Balance On Second Anniversary
Guarantee Obligations Balance On Third Anniversary
Guarantee Obligations Balance On Fourth Anniversary
Guarantee Obligations Balance On Fifth Anniversary
Guarantee Obligations Due After Five Years
Guarantor Obligations, Maximum Exposure, Undiscounted
10 2
Gurantee Obligations Total [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
590 
Guarantee Obligations Balance On Second Anniversary
80 
Guarantee Obligations Balance On Third Anniversary
37 
Guarantee Obligations Balance On Fourth Anniversary
36 
Guarantee Obligations Balance On Fifth Anniversary
45 
Guarantee Obligations Due After Five Years
243 
Guarantor Obligations, Maximum Exposure, Undiscounted
$ 1,031 
Segment and Significant Customer Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
$ 1,367 
$ 1,996 
$ 879 
$ 1,236 
$ 1,459 
$ 2,209 
$ 1,633 
$ 1,499 
$ 5,478 
$ 6,800 
$ 6,545 
Intersegment revenues
 
 
 
 
 
 
 
 
Total operating revenues
 
 
 
 
 
 
 
 
5,478 
6,800 
6,545 
Commodity Margin
 
 
 
 
 
 
 
 
2,538 1 2
2,474 1 2
2,391 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(84)3
(33)3
171 
Plant operating expense
 
 
 
 
 
 
 
 
922 
904 
868 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
562 
550 
570 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
140 
131 
151 
Other operating expenses
 
 
 
 
 
 
 
 
78 
77 
91 
Impairment losses
 
 
 
 
 
 
 
 
 
 
116 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
(222)
(119)
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
(28)
(21)
(16)
Income from operations
295 
705 
(193)
195 
196 
403 
183 
18 
1,002 
800 
901 
Interest expense, net of interest income
 
 
 
 
 
 
 
 
725 
751 
802 
Loss on interest rate derivatives
 
 
 
 
 
 
 
 
14 
145 
223 
Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
45 
115 
106 
Income (loss) before income taxes and discontinued operations
 
 
 
 
 
 
 
 
218 
(211)
(230)
Commodity Margin Riverside Energy Center
 
 
 
 
 
 
 
 
73 
70 
73 
Commodity Margin Broad River Energy Center
 
 
 
 
 
 
 
 
52 
51 
55 
Lease levelization
 
 
 
 
 
 
 
 
12 
 
Contract amortization
 
 
 
 
 
 
 
 
14 
 
Number of significant customers
 
 
 
 
 
 
 
 
 
 
West [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
1,668 
2,372 
2,525 
Intersegment revenues
 
 
 
 
 
 
 
 
10 
12 
12 
Total operating revenues
 
 
 
 
 
 
 
 
1,678 
2,384 
2,537 
Commodity Margin
 
 
 
 
 
 
 
 
994 1 2
1,061 1 2
1,080 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(93)3
113 3
69 
Plant operating expense
 
 
 
 
 
 
 
 
368 
380 
351 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
203 
192 
207 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
36 
43 
55 
Other operating expenses
 
 
 
 
 
 
 
 
42 
41 
59 
Impairment losses
 
 
 
 
 
 
 
 
 
 
97 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
Income from operations
 
 
 
 
 
 
 
 
252 
518 
380 
Texas [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
1,857 
2,306 
2,162 
Intersegment revenues
 
 
 
 
 
 
 
 
61 
23 
22 
Total operating revenues
 
 
 
 
 
 
 
 
1,918 
2,329 
2,184 
Commodity Margin
 
 
 
 
 
 
 
 
570 1 2
469 1 2
504 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
87 3
(102)3
89 
Plant operating expense
 
 
 
 
 
 
 
 
247 
235 
285 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
142 
135 
150 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
47 
43 
38 
Other operating expenses
 
 
 
 
 
 
 
 
Impairment losses
 
 
 
 
 
 
 
 
 
 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
(119)
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
Income from operations
 
 
 
 
 
 
 
 
216 
(49)
237 
North [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
1,280 
1,336 
978 
Intersegment revenues
 
 
 
 
 
 
 
 
14 
Total operating revenues
 
 
 
 
 
 
 
 
1,294 
1,343 
984 
Commodity Margin
 
 
 
 
 
 
 
 
729 1 2
704 1 2
535 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(14)3
(13)3
21 
Plant operating expense
 
 
 
 
 
 
 
 
206 
177 
138 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
134 
138 
111 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
28 
24 
45 
Other operating expenses
 
 
 
 
 
 
 
 
29 
30 
28 
Impairment losses
 
 
 
 
 
 
 
 
 
 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
(7)
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
(28)
(21)
(16)
Income from operations
 
 
 
 
 
 
 
 
353 
343 
250 
Southeast [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
673 
786 
880 
Intersegment revenues
 
 
 
 
 
 
 
 
80 
135 
138 
Total operating revenues
 
 
 
 
 
 
 
 
753 
921 
1,018 
Commodity Margin
 
 
 
 
 
 
 
 
245 1 2
240 1 2
272 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(33)3
3
22 
Plant operating expense
 
 
 
 
 
 
 
 
131 
141 
123 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
85 
90 
109 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
29 
22 
12 
Other operating expenses
 
 
 
 
 
 
 
 
Impairment losses
 
 
 
 
 
 
 
 
 
 
19 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
(215)
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
Income from operations
 
 
 
 
 
 
 
 
177 
(17)
27 
Consolidation and Elimination [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
Intersegment revenues
 
 
 
 
 
 
 
 
(165)
(177)
(178)
Total operating revenues
 
 
 
 
 
 
 
 
(165)
(177)
(178)
Commodity Margin
 
 
 
 
 
 
 
 
1 2
1 2
1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(31)3
(32)3
(30)
Plant operating expense
 
 
 
 
 
 
 
 
(30)
(29)
(29)
Depreciation and amortization expense
 
 
 
 
 
 
 
 
(2)
(5)
(7)
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
(1)
Other operating expenses
 
 
 
 
 
 
 
 
(3)
(2)
(2)
Impairment losses
 
 
 
 
 
 
 
 
 
 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
Income from operations
 
 
 
 
 
 
 
 
PJM Settlement, Inc. [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Major customer revenue
 
 
 
 
 
 
 
 
713 
742 
 
Major customer receivables
 
 
 
 
 
 
 
 
$ 37 
$ 28 
 
Quarterly Consolidated Financial Data (unaudited) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Quarterly Financial Information Disclosure [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Total Operating revenues
$ 1,367 
$ 1,996 
$ 879 
$ 1,236 
$ 1,459 
$ 2,209 
$ 1,633 
$ 1,499 
$ 5,478 
$ 6,800 
$ 6,545 
Income (loss) from operations
295 
705 
(193)
195 
196 
403 
183 
18 
1,002 
800 
901 
Net income (loss) attributable to Calpine
$ 100 
$ 437 
$ (329)
$ (9)
$ (13)
$ 190 
$ (70)
$ (297)
$ 199 
$ (190)
$ 31 
Net income (loss) per common share attributable to Calpine — basic (in dollars per share)
$ 0.22 
$ 0.95 
$ (0.69)
$ (0.02)
$ (0.03)
$ 0.39 
$ (0.14)
$ (0.61)
$ 0.43 
$ (0.39)
$ 0.06 
Net income (loss) per common share attributable to Calpine — diluted (in dollars per share)
$ 0.22 
$ 0.94 
$ (0.69)
$ (0.02)
$ (0.03)
$ 0.39 
$ (0.14)
$ (0.61)
$ 0.42 
$ (0.39)
$ 0.06 
Schedule of Valuation and Qualifying Accounts Disclosure (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Allowance for Doubtful Accounts [Member]
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Balance at Beginning of Year
$ 13 
$ 2 
$ 14 
Charged to Expense
(1)
(12)
Deductions
(5)1
1
1
Charged to Other Accounts
(1)
Balance at End of Year
13 
Deferred Tax Asset Valuation Allowance [Member]
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Balance at Beginning of Year
2,336 
2,386 
2,572 
Charged to Expense
(114)
(50)
(186)
Deductions
1
1
1
Charged to Other Accounts
Balance at End of Year
$ 2,222 
$ 2,336 
$ 2,386