CALPINE CORP, 10-K filed on 2/13/2014
Annual Report
Document and Entity Information Cover (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Feb. 10, 2014
Jun. 30, 2013
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, 2013 
 
 
Document Fiscal Year Focus
2013 
 
 
Document Fiscal Period Focus
FY 
 
 
Amendment Flag
false 
 
 
Entity Common Stock, Shares Outstanding
 
422,950,351 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Public Float
 
 
$ 9,361 
Consolidated Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Operating revenues:
 
 
 
Commodity revenue
$ 6,374 
$ 5,417 
$ 6,753 
Unrealized mark-to-market gain (loss)
(86)
48 
35 
Other revenue
13 
13 
12 
Operating revenues
6,301 
5,478 
6,800 
Operating expenses:
 
 
 
Commodity expense
3,808 
2,894 
4,299 
Unrealized mark-to-market (gain) loss
(72)
130 
60 
Fuel and purchased energy expense
3,736 
3,024 
4,359 
Plant operating expense
895 
922 
904 
Depreciation and amortization expense
609 
562 
550 
Sales, general and other administrative expense
136 
140 
131 
Other operating expenses
81 
78 
77 
Total operating expenses
5,457 
4,726 
6,021 
(Gain) on sale of assets, net
0 
(222)
0 
(Income) from unconsolidated investments in power plants
(30)
(28)
(21)
Income from operations
874 
1,002 
800 
Interest expense
696 
736 
760 
Loss on interest rate derivatives
0 
14 
145 
Interest (income)
(6)
(11)
(9)
Debt extinguishment costs
144 
30 
94 
Other (income) expense, net
20 
15 
21 
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest
20 
218 
(211)
Income tax expense (benefit)
2 
19 
(22)
Net income (loss)
18 
199 
(189)
Net income attributable to the noncontrolling interest
(4)
0 
(1)
Net income (loss) attributable to Calpine
$ 14 
$ 199 
$ (190)
Basic earnings (loss) per common share attributable to Calpine:
 
 
 
Weighted average shares of common stock outstanding (in shares)
440,666 
467,752 
485,381 
Net income (loss) per common share attributable to Calpine — basic (in dollars per share)
$ 0.03 
$ 0.43 
$ (0.39)
Diluted earnings (loss) per common share attributable to Calpine:
 
 
 
Weighted average shares of common stock outstanding (in shares)
444,773 
471,343 
485,381 
Net income (loss) per common share attributable to Calpine — diluted (in dollars per share)
$ 0.03 
$ 0.42 
$ (0.39)
Consolidated Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Net income (loss)
$ 18 
$ 199 
$ (189)
Cash flow hedging activities:
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
35 
(61)
(69)
Reclassification adjustment for (gain) loss on cash flow hedges realized in net income (loss)
51 
(20)
(25)
Unrealized actuarial gains (losses) arising during period
4 
(1)
(3)
Foreign currency translation gain (loss)
(10)
3 
(1)
Income tax (expense) benefit
(3)
9 
45 
Other comprehensive income (loss)
77 
(70)
(53)
Comprehensive income (loss)
95 
129 
(242)
Comprehensive (income) loss attributable to the noncontrolling interest
(13)
6 
13 
Comprehensive income (loss) attributable to Calpine
$ 82 
$ 135 
$ (229)
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Current assets:
 
 
Cash and cash equivalents ($242 and $109 attributable to VIEs)
$ 941 
$ 1,284 
Accounts receivable, net of allowance of $5 and $6
552 
437 
Margin deposits and other prepaid expense
309 
244 
Restricted cash, current ($100 and $53 attributable to VIEs)
203 
193 
Derivative assets, current
445 
339 
Inventory and other current assets
406 
335 
Total current assets
2,856 
2,832 
Property, plant and equipment, net ($4,191 and $4,192 attributable to VIEs)
12,995 
13,005 
Restricted cash, net of current portion ($68 and $59 attributable to VIEs)
69 
60 
Investments in power plants
93 
81 
Long-term derivative assets
105 
98 
Other assets
441 
473 
Total assets
16,559 
16,549 
Current liabilities:
 
 
Accounts payable
462 
382 
Accrued interest payable
162 
180 
Debt, current portion ($140 and $39 attributable to VIEs)
204 
115 
Derivative liabilities, current
451 
357 
Income taxes payable
7 
11 
Other current liabilities
245 
273 
Total current liabilities
1,531 
1,318 
Debt, net of current portion ($2,923 and $2,660 attributable to VIEs)
10,908 
10,635 
Long-term derivative liabilities
243 
293 
Other long-term liabilities
309 
247 
Total liabilities
12,991 
12,493 
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, 2013 and 2012
0 
0 
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 497,841,056 shares issued and 429,038,988 shares outstanding at December 31, 2013, and 492,495,100 shares issued and 457,048,970 shares outstanding at December 31, 2012
1 
1 
Treasury stock, at cost, 68,802,068 and 35,446,130 shares, respectively
(1,230)
(594)
Additional paid-in capital
12,389 
12,335 
Accumulated deficit
(7,486)
(7,500)
Accumulated other comprehensive loss
(160)
(228)
Total Calpine stockholders’ equity
3,514 
4,014 
Noncontrolling interest
54 
42 
Total stockholders’ equity
3,568 
4,056 
Total liabilities and stockholders’ equity
$ 16,559 
$ 16,549 
Consolidated Balance Sheets Consolidated Balance Sheets Parentheticals (USD $)
In Millions, except Share data, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Cash and cash equivalents ($242 and $109 attributable to VIEs)
$ 941 
$ 1,284 
Accounts Receivable, allowance for doubtful accounts
5 
6 
Restricted cash, current ($100 and $53 attributable to VIEs)
203 
193 
Property, plant and equipment, net ($4,191 and $4,192 attributable to VIEs)
12,995 
13,005 
Restricted cash, net of current portion ($68 and $59 attributable to VIEs)
69 
60 
Debt, current portion ($140 and $39 attributable to VIEs)
204 
115 
Debt, net of current portion ($2,923 and $2,660 attributable to VIEs)
10,908 
10,635 
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)
0 
0 
Preferred Stock, outstanding shares (in shares)
0 
0 
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)
497,841,056 
492,495,100 
Common Stock, outstanding shares (in shares)
429,038,988 
457,048,970 
Treasury Stock, shares (in shares)
68,802,068 
35,446,130 
Variable Interest Entity, Primary Beneficiary [Member]
 
 
Cash and cash equivalents ($242 and $109 attributable to VIEs)
242 
109 
Restricted cash, current ($100 and $53 attributable to VIEs)
100 
53 
Property, plant and equipment, net ($4,191 and $4,192 attributable to VIEs)
4,191 
4,192 
Restricted cash, net of current portion ($68 and $59 attributable to VIEs)
68 
59 
Debt, current portion ($140 and $39 attributable to VIEs)
140 
39 
Debt, net of current portion ($2,923 and $2,660 attributable to VIEs)
$ 2,923 
$ 2,660 
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, 2010
$ 4,669 
$ 1 
$ (5)
$ 12,281 
$ (7,509)
$ (125)
$ 26 
Treasury stock transactions
(120)
0 
(120)
0 
0 
0 
0 
Stock-based compensation expense
24 
0 
0 
24 
0 
0 
0 
Option exercises
0 
 
 
 
 
 
 
Other
33 
0 
0 
0 
0 
0 
33 
Net income (loss)
(189)
0 
0 
0 
(190)
0 
1 
Other comprehensive income (loss)
(53)
0 
0 
0 
0 
(39)
(14)
Balance at Dec. 31, 2011
4,364 
1 
(125)
12,305 
(7,699)
(164)
46 
Treasury stock transactions
(469)
0 
(469)
0 
0 
0 
0 
Stock-based compensation expense
25 
0 
0 
25 
0 
0 
0 
Option exercises
5 
0 
0 
5 
0 
0 
0 
Other
2 
0 
0 
0 
0 
0 
2 
Net income (loss)
199 
0 
0 
0 
199 
0 
0 
Other comprehensive income (loss)
(70)
0 
0 
0 
0 
(64)
(6)
Balance at Dec. 31, 2012
4,056 
1 
(594)
12,335 
(7,500)
(228)
42 
Treasury stock transactions
(636)
0 
(636)
0 
0 
0 
0 
Stock-based compensation expense
34 
0 
0 
34 
0 
0 
0 
Option exercises
20 
0 
0 
20 
0 
0 
0 
Other
(1)
0 
0 
0 
0 
0 
(1)
Net income (loss)
18 
0 
0 
0 
14 
0 
4 
Other comprehensive income (loss)
77 
0 
0 
0 
0 
68 
9 
Balance at Dec. 31, 2013
$ 3,568 
$ 1 
$ (1,230)
$ 12,389 
$ (7,486)
$ (160)
$ 54 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Cash flows from operating activities:
 
 
 
Net income (loss)
$ 18 
$ 199 
$ (189)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense(1)
654 1
605 1
587 1
Debt extinguishment costs
43 
0 
82 
Deferred income taxes
14 
1 
(21)
(Gain) loss on sale of power plants and other, net
4 
(212)
13 
Unrealized mark-to-market activity, net
12 2
(72)2
(30)2
(Income) from unconsolidated investments in power plants
(30)
(28)
(21)
Return on unconsolidated investments in power plants
25 
24 
6 
Stock-based compensation expense
36 
25 
24 
Change in operating assets and liabilities, net of effects of acquisitions:
(3)
1 
6 
Change in operating assets and liabilities, net of effects of acquisitions:
 
 
 
Accounts receivable
(113)
159 
74 
Derivative instruments, net
(7)
(52)
15 
Other assets
(148)
(57)
1 
Accounts payable and accrued expenses
(1)
(86)
28 
Settlement of non-hedging interest rate swaps
0 
156 
189 
Other liabilities
45 
(10)
11 
Net cash provided by operating activities
549 
653 
775 
Cash flows from investing activities:
 
 
 
Purchases of property, plant and equipment
(575)
(637)
(683)
Proceeds from sale of power plants, interests and other
1 
825 
13 
Purchase of Bosque Energy Center, net of cash
0 
(432)
0 
Return of investment from unconsolidated investments in power plants
2 
5 
0 
Settlement of non-hedging interest rate swaps
0 
(156)
(189)
(Increase) decrease in restricted cash
(18)
(59)
54 
Purchases of deferred transmission credits
0 
(12)
(31)
Other
(3)
(4)
0 
Net cash used in investing activities
(593)
(470)
(836)
Cash flows from financing activities:
 
 
 
Borrowings under First Lien Term Loans
390 
835 
1,657 
Repayments of First Lien Term Loans
(25)
(19)
0 
Borrowings from CCFC Term Loans
1,197 
0 
0 
Repayments under CCFC Term Loans
(6)
0 
0 
Repayment of CCFC Notes
(1,000)
0 
0 
Repayments on NDH Project Debt
0 
0 
(1,283)
Borrowings under First Lien Notes
1,234 
0 
1,200 
Repayments of First Lien Notes
(1,550)
(590)
0 
Repayments on First Lien Credit Facility
0 
0 
(1,195)
Borrowings from project financing, notes payable and other
182 
389 
327 
Repayments of project financing, notes payable and other
(66)
(289)
(550)
Capital contributions from noncontrolling interest holder
0 
0 
33 
Financing costs
(53)
(20)
(81)
Stock repurchases
(623)
(463)
(119)
Proceeds from exercises of stock options
20 
5 
0 
Other
1 
1 
(3)
Net cash used in financing activities
(299)
(151)
(14)
Net increase (decrease) in cash and cash equivalents
(343)
32 
(75)
Cash and cash equivalents, beginning of period
1,284 
1,252 
1,327 
Cash and cash equivalents, end of period
941 
1,284 
1,252 
Cash paid during the period for:
 
 
 
Interest, net of amounts capitalized
672 
719 
656 
Income taxes
24 
16 
18 
Supplemental disclosure of non-cash investing activities:
 
 
 
Change in capital expenditures included in accounts payable
27 
19 
(24)
Other non-cash additions to property, plant and equipment
$ 0 
$ 13 
$ 0 
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 purchase natural gas and fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas and power physical and financial contracts to hedge certain 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.
Reclassifications — Certain reclassifications have been made to our Consolidated Balance Sheet as of December 31, 2012, and our Statements of Comprehensive Income (Loss), Stockholders' Equity and Cash Flows for the years ended December 31, 2012 and 2011, to conform to the current year presentation. Our reclassifications are summarized as follows:
•
We have reclassified $(6) million and $(14) million related to our noncontrolling interest's portion of cash flow hedge losses, net of tax, in OCI to comprehensive income (loss) attributable to the noncontrolling interest for the years ended December 31, 2012 and 2011, respectively, on our Consolidated Statements of Comprehensive Income (Loss). This reclassification is also reflected in the AOCI and noncontrolling interest balances on our Consolidated Balance Sheet as of December 31, 2012 and on our Consolidated Statements of Stockholders' Equity for the years ended December 31, 2012 and 2011.
•
We have reclassified $5 million and nil on our Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011, respectively, to separately report proceeds from the exercises of stock options, previously reflected in other cash flows used in financing activities.
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, 2013
 
Ownership Interest
 
Property, Plant & Equipment
 
Accumulated Depreciation
 
Construction in Progress
(in millions, except percentages)
Freestone Energy Center
 
75.0
%
 
$
393

 
$
(135
)
 
$
—

Hidalgo Energy Center
 
78.5
%
 
$
255

 
$
(93
)
 
$
—

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 Note 7 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, 2013 and 2012, we had cash and cash equivalents of $292 million and $131 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, 2013 and 2012 (in millions):
 
 
2013
 
2012
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
11

 
$
41

 
$
52

 
$
11

 
$
41

 
$
52

Rent reserve
3

 
—

 
3

 
—

 
—

 
—

Construction/major maintenance
35

 
20

 
55

 
32

 
14

 
46

Security/project/insurance
151

 
6

 
157

 
101

 
3

 
104

Other
3

 
2

 
5

 
49

 
2

 
51

Total
$
203

 
$
69

 
$
272

 
$
193

 
$
60

 
$
253

___________
(1)
At December 31, 2013 and 2012, amounts restricted for debt service included approximately $24 million and $25 million, respectively, 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, 2013 and 2012, we had inventory of $364 million and $301 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental products 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, certain replacements or repairs when the repairs 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 power plant or have a favorable option to purchase the power plant or take ownership of the power plant 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 2013, 2012 and 2011, we did not record any material impairment losses.
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, 2013 and 2012, our asset retirement obligation liabilities were $44 million and $38 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 at December 31, 2013, are as follows (in millions):
2014
$
632

2015
641

2016
582

2017
546

2018
517

Thereafter
2,577

Total
$
5,495


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 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 natural gas transactions economically hedging anticipated future power sales that 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.
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
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. We adopted Accounting Standards Updates 2011-11 and 2013-01 as of January 1, 2013. As these updates only required additional disclosures, adoption of these standards did not have a material impact on our financial condition, results of operations or cash flows. See Note 8 for disclosures regarding our assets and liabilities that are presented gross on our Consolidated Balance Sheets when the right of offset exists, or that are subject to an enforceable master netting arrangement.
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. We adopted Accounting Standards Update 2013-02 as of January 1, 2013. As this update only required additional disclosures, adoption of this standard did not have a material impact on our financial condition, results of operations or cash flows. See Note 8 for disclosures on the affect of significant reclassifications out of AOCI on the respective line items on our Consolidated Statements of Operations.
Income Taxes — In July 2013, the FASB issued Accounting Standards Update 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists”. The provisions of the rule require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The new financial statement presentation provisions relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2013, with early adoption permitted. We are currently assessing the future impact of this update, but we do not anticipate a material impact on our financial condition, results of operations or cash flows.
Acquisitions, Divestitures and Discontinued Operations Acquisitions and Divestitures (Notes)
Mergers, Acquisitions and Dispositions Disclosures [Text Block]
Acquisitions and Divestitures
Acquisition of Guadalupe Energy Center
On December 2, 2013, we announced that we have entered into an agreement, through our indirect, wholly-owned subsidiary Calpine Guadalupe GP, LLC, to purchase a power plant with a nameplate capacity of 1,050 MW owned by MinnTex Power Holdings, LLC, for approximately $625 million . The natural gas-fired, combined-cycle power plant will increase capacity in our Texas segment and is located in Guadalupe County, Texas, which is located northeast of San Antonio, Texas. The 110 acre site includes two 525 MW generation blocks, each consisting of two GE 7FA combustion turbines, two heat recovery steam generators and one GE steam turbine. The purchase price does not include $15 million in consideration for the rights we also acquired to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker, if market conditions warrant. We expect the transaction to close in the first quarter of 2014, subject to regulatory approvals, and will fund the acquisition with cash on hand or with cash on hand and financing.
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. We did not record any material adjustments to the preliminary purchase price allocation during 2013, which is now final, nor any goodwill as a result of this acquisition.
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 used 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 used 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.
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net
As of December 31, 2013 and 2012, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
2013
 
2012
 
Depreciable Lives
Buildings, machinery and equipment(1)
$
15,838

 
$
14,774

 
3 – 47 Years
Geothermal properties
1,265

 
1,243

 
13 – 59 Years
Other
164

 
142

 
3 – 47 Years
 
17,267

 
16,159

 
 
Less: Accumulated depreciation
4,897

 
4,390

 
 
 
12,370

 
11,769

 
 
Land
103

 
98

 
 
Construction in progress(1)
522

 
1,138

 
 
Property, plant and equipment, net
$
12,995

 
$
13,005

 
 

___________
(1)
The change from December 31, 2012 to December 31, 2013 is primarily attributed to our Russell City and Los Esteros power plants commencing commercial operations during 2013.
We have various debt instruments that are collateralized by our property, plant and equipment. See Note 6 for a 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 power plants and related equipment associated with 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, $38 million and $24 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the year ended December 31, 2013. 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. 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 9,027 MW and 8,255 MW, at December 31, 2013 and 2012, 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. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil, $20 million and $87 million for the years ended December 31, 2013, 2012 and 2011, respectively.
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 in Power Plants
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. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries 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.
We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Balance Sheets. At December 31, 2013 and 2012, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of December 31, 2013
 
2013
 
2012
Greenfield LP
50%
 
$
76

 
$
69

Whitby
50%
 
17

 
12

Total investments in power plants
 
 
$
93

 
$
81


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, 2013 and 2012, equity method investee debt was approximately $395 million and $448 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $198 million and $224 million at December 31, 2013 and 2012, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2013, 2012 and 2011, is 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
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Greenfield LP
$
(16
)
 
$
(17
)
 
$
(12
)
 
$
18

 
$
22

 
$
2

Whitby
(14
)
 
(11
)
 
(9
)
 
9

 
7

 
4

Total
$
(30
)
 
$
(28
)
 
$
(21
)
 
$
27

 
$
29

 
$
6


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) 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 years ended December 31, 2013 and 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, 2013 and 2012

 
2013
 
2012
Assets:
 
 
 
Cash and cash equivalents
$
57

 
$
64

Current assets
25

 
30

Property, plant and equipment, net
588

 
648

Other assets
2

 
4

Total assets
$
672

 
$
746

Liabilities:
 
 
 
Current maturities of long-term debt
$
23

 
$
25

Current liabilities
44

 
36

Long-term debt
372

 
423

Long-term derivative liabilities
35

 
84

Total liabilities
474

 
568

Member's interest
198

 
178

Total liabilities and member's interest
$
672

 
$
746


Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
For the Years Ended December 31, 2013, 2012 and 2011

 
2013
 
2012
 
2011
Revenues
$
207

 
$
247

 
$
277

Operating expenses
128

 
171

 
208

Income from operations
79

 
76

 
69

Interest expense, net of interest income
24

 
27

 
30

Other (income) expense, net
(3
)
 
(2
)
 
2

Net income
$
58

 
$
51

 
$
37

Debt
Debt
Debt
Our debt at December 31, 2013 and 2012, was as follows (in millions):
 
2013
 
2012
First Lien Notes
$
4,989

 
$
5,303

First Lien Term Loans
2,828

 
2,463

Project financing, notes payable and other
1,901

 
1,789

CCFC Term Loans
1,191

 
—

CCFC Notes
—

 
978

Capital lease obligations
203

 
217

Subtotal
11,112

 
10,750

Less: Current maturities
204

 
115

Total long-term debt
$
10,908

 
$
10,635


Our debt agreements contain covenants which could permit lenders to accelerate the repayment of our debt by providing notice, the lapse of time, or both, if certain events of default remain uncured after any applicable grace period. We were in compliance with all of the covenants in our debt agreements at December 31, 2013.
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2013, are as follows (in millions):
 
2014
$
205

2015
183

2016
194

2017
550

2018
1,717

Thereafter
8,291

Subtotal
11,140

Less: Discount
28

Total debt
$
11,112


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(3)
 
2013
 
2012
 
2013
 
2012
2017 First Lien Notes(1)
$
—

 
$
1,080

 
—
%
 
7.5
%
2019 First Lien Notes(2)
320

 
360

 
8.2

 
8.2

2020 First Lien Notes(2)
875

 
983

 
8.2

 
8.1

2021 First Lien Notes(2)
1,600

 
1,800

 
7.7

 
7.7

2022 First Lien Notes(1)
744

 
—

 
6.2

 
—

2023 First Lien Notes(2)
960

 
1,080

 
8.0

 
8.0

2024 First Lien Notes(2)
490

 
—

 
5.9

 
—

Total First Lien Notes
$
4,989

 
$
5,303

 
 
 
 
____________
(1)
On October 17, 2013, we launched a tender offer to repay our 2017 First Lien Notes with the proceeds from our 2020 First Lien Term Loan and 2022 First Lien Notes which are described in further detail below. On October 31, 2013, following the early tender and consent date of the tender offer, we purchased approximately $742 million in aggregate principal amount of our 2017 First Lien Notes and issued a redemption notice to the remaining holders of our 2017 First Lien Notes that did not tender their notes in the tender offer. The tender offer expired on November 29, 2013 and we purchased the remaining $338 million in aggregate principal amount of our 2017 First Lien Notes tendered prior to the expiration of the tender offer, and redeemed any remaining 2017 First Lien Notes on December 2, 2013.
(2)
On October 31, 2013, we issued $490 million in aggregate principal amount of our 2024 First Lien Notes and used the proceeds to redeem 10% of the original aggregate principal amount of our 2019 First Lien Notes, 2020 First Lien Notes, 2021 First Lien Notes and 2023 First Lien Notes at a redemption price of 103% of the principal amount redeemed, plus accrued and unpaid interest.
(3)
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.
2022 First Lien Notes
On October 31, 2013, we issued $750 million in aggregate principal amount of 6.0% senior secured notes due 2022 in a private placement. The 2022 First Lien Notes bear interest at 6.0% payable semi-annually on January 15 and July 15 of each year, beginning on July 15, 2014. We used the net proceeds received, together with the proceeds from the 2020 First Lien Term Loan, to repay the 2017 First Lien Notes during the fourth quarter of 2013. The 2022 First Lien Notes mature on January 15, 2022.
    The 2022 First Lien Notes were offered to investors at an issue price equal to 99.193% of face value and contain substantially similar covenants, qualifications, exceptions and limitations as the First Lien Notes. We recorded approximately $12 million in deferred financing costs related to our 2022 First Lien Notes and approximately $51 million of debt extinguishment costs associated with the redemption premium and write-off of unamortized deferred financing costs related to the repayment of our 2017 First Lien Notes during the fourth quarter of 2013.
2024 First Lien Notes
On October 31, 2013, we issued $490 million in aggregate principal amount of 5.875% senior secured notes due 2024 in a private placement. The 2024 First Lien Notes bear interest at 5.875% payable semi-annually on January 15 and July 15 of each year, beginning on January 15, 2014. We used the net proceeds received from this issuance to redeem 10% of the original aggregate principal amount of our 2019 First Lien Notes, 2020 First Lien Notes, 2021 First Lien Notes and 2023 First Lien Notes at a redemption price of 103% of the principal amount redeemed, plus accrued and unpaid interest. The 2024 First Lien Notes mature on January 15, 2024.
    The 2024 First Lien Notes contain substantially similar covenants, qualifications, exceptions and limitations as the First Lien Notes. We recorded approximately $8 million in deferred financing costs related to our 2024 First Lien Notes and approximately $20 million of debt extinguishment costs associated with the redemption premium and write-off of unamortized deferred financing costs and discount during the fourth quarter of 2013.
First Lien Term Loans
Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates):
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2013
 
2012
 
2013
 
2012
2018 First Lien Term Loans
$
1,614

 
$
1,630

 
4.3
%
 
4.7
%
2019 First Lien Term Loan
824

 
833

 
4.5

 
4.7

2020 First Lien Term Loan
390

 
—

 
4.3

 
—

Total First Lien Term Loans
$
2,828

 
$
2,463

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
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 2.0%, or (ii) LIBOR plus 3.0% per annum subject to a LIBOR floor of 1.0%. 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. The 2019 First Lien Term Loan carries substantially the same terms as the 2018 First Lien Term Loans and matures on October 9, 2019.
2020 First Lien Term Loan
On October 23, 2013, we entered into our $390 million 2020 First Lien Term Loan. We used the net proceeds received, together with the proceeds from the 2022 First Lien Notes to repay the 2017 First Lien Notes during the fourth quarter of 2013. The 2020 First Lien Term Loan matures on October 31, 2020 and carries substantially the same terms as the First Lien Term Loans. The 2020 First Lien Term Loan also contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and First Lien Notes. We recorded approximately $6 million in deferred financing costs during the fourth quarter of 2013 related to the issuance of the 2020 First Lien Term Loan.
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)
 
2013
 
2012
 
2013
 
2012
Russell City Project Debt due 2023
$
593

 
$
507

 
4.9
%
 
3.6
%
Steamboat due 2017
418

 
428

 
6.8

 
6.8

OMEC due 2019
335

 
345

 
6.9

 
6.8

Los Esteros Project Debt due 2023
305

 
209

 
3.4

 
3.5

Pasadena(2)
135

 
160

 
8.9

 
8.9

Bethpage Energy Center 3 due 2020-2025(3)
88

 
93

 
7.0

 
7.0

Gilroy note payable due 2014
15

 
33

 
11.2

 
10.8

Other
12

 
14

 
—

 
—

Total
$
1,901

 
$
1,789

 
 
 
 
_____________
(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.
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 Term Loans and Repayment of CCFC Notes
Our CCFC Term Loans and CCFC Notes are summarized in the table below (in millions, except for interest rates):
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2013
 
2012
 
2013
 
2012
CCFC Term Loans
$
1,191

 
$
—

 
3.3
%
 
—
%
CCFC Notes
—

 
978

 
—

 
8.9

Total CCFC Term Loans and CCFC Notes
$
1,191

 
$
978

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
CCFC Term Loans
On May 3, 2013, CCFC entered into a credit agreement providing for a first lien senior secured term loan facility comprised of (i) a $900 million 7-year term loan and (ii) a $300 million 8.5-year term loan.
CCFC utilized the proceeds received from the CCFC Term Loans to redeem the entire $1.0 billion in principal amount of CCFC Notes at a redemption price equal to 104% (plus accrued and unpaid interest), to pay related transaction expenses and for corporate purposes, as described in the credit agreement. The CCFC Notes were redeemed on June 3, 2013, at which date the CCFC Term Loans were fully drawn.
The CCFC Term Loans bear interest, at CCFC’s option, at either (i) the Base Rate, equal to the higher of the Federal Funds Effective Rate plus 0.50% per annum or the Prime Rate (as such terms are defined in the Credit Agreement), plus an applicable margin of (a) 1.25% per annum with respect to the 7-year term loan and (b) 1.50% per annum with respect to the 8.5-year term loan, or (ii) LIBOR plus (a) 2.25% per annum with respect to the 7-year term loan and (b) 2.50% per annum with respect to the 8.5-year term loan (in each case subject to a LIBOR floor of 0.75%). The term loans were offered to investors at an issue price equal to 99.75% of face value.
An amount equal to 0.25% of the aggregate principal amount of the CCFC Term Loans are payable at the end of each quarter commencing in September 2013, with the remaining balance payable on the relevant maturity date (May 3, 2020 with respect to the 7-year term loan and January 31, 2022 with respect to the 8.5-year term loan). CCFC may elect from time to time to convert all or a portion of the CCFC Term Loans from LIBOR loans to Base Rate loans or vice versa. In addition, CCFC may at any time, and from time to time, prepay the term loans, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent.
The CCFC Term Loans are secured by certain real and personal property of CCFC consisting primarily of six natural gas-fired power plants. The CCFC Term Loans are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any of our non-CCFC subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation.
In connection with the redemption of the CCFC Notes, we recorded $68 million in debt extinguishment costs associated with prepayment penalties and the write-off of unamortized debt discount and deferred financing costs during the year ended December 31, 2013. We also recorded $15 million in new deferred financing costs on our Consolidated Balance Sheet during 2013 associated with the issuance of the CCFC Term Loans.
Capital Lease Obligations
The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the net minimum lease payments as of December 31, 2013 (in millions):
 
Sale-Leaseback Transactions(1)
 
Capital Lease
 
Total
2014
$
25

 
$
51

 
$
76

2015
25

 
38

 
63

2016
25

 
40

 
65

2017
17

 
38

 
55

2018
21

 
37

 
58

Thereafter
106

 
125

 
231

Total minimum lease payments
219

 
329

 
548

Less: Amount representing interest
84

 
126

 
210

Present value of net minimum lease payments
$
135

 
$
203

 
$
338

____________
(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 35 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, 2013 and 2012, the asset balances for the leased assets totaled approximately $862 million and $880 million with accumulated amortization of $343 million and $312 million, respectively. Amortization of assets under capital leases is recorded in depreciation and amortization expense on our Consolidated Statements of Operations. 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, 2013 and 2012 (in millions):
 
2013
 
2012
Corporate Revolving Facility
$
242

 
$
243

CDHI
218

 
253

Various project financing facilities
170

 
130

Total
$
630

 
$
626


On June 27, 2013, we executed Amendment No.1 to the Corporate Revolving Facility. Certain key terms of the amendment are listed below:
•
the applicable margin has been reduced from 3.25% to 2.25% for LIBOR rate borrowings and from 2.25% to 1.25% for base rate borrowings;
•
the fee on the undrawn commitment has been reduced from 0.75% to 0.50%; and
•
the maturity date of the Corporate Revolving Facility has been extended to June 27, 2018.
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 1.00% to 1.25% 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 2.00% to 2.25%. 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 0.25% to 0.50% 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 $3.0 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 June 27, 2018.
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 have $300 million letter of credit facility related to CDHI which matures on 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, 2013, we had no outstanding letters of credit issued in excess of $225 million under our CDHI letter of credit facility that were collateralized by cash.
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, 2013 and 2012 (in millions):
 
2013
 
2012
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
5,317

 
$
4,989

 
$
5,863

 
$
5,303

First Lien Term Loans
2,845

 
2,828

 
2,489

 
2,463

Project financing, notes payable and other(1)
1,772

 
1,766

 
1,599

 
1,629

CCFC Term Loans
1,179

 
1,191

 
—

 
—

CCFC Notes
—

 
—

 
1,075

 
978

Total
$
11,113

 
$
10,774

 
$
11,026

 
$
10,373

____________
(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, CCFC 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 Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits posted with us 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 power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
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 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. 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, 2013 and 2012, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2013
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,134

 
$
—

 
$
—

 
$
1,134

Margin deposits
261

 
—

 
—

 
261

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
434

 
—

 
—

 
434

Commodity forward contracts(2)
—

 
75

 
32

 
107

Interest rate swaps
—

 
9

 
—

 
9

Total assets
$
1,829

 
$
84

 
$
32

 
$
1,945

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
5

 
$
—

 
$
—

 
$
5

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
495

 
—

 
—

 
495

Commodity forward contracts(2)
—

 
52

 
18

 
70

Interest rate swaps
—

 
129

 
—

 
129

Total liabilities
$
500

 
$
181

 
$
18

 
$
699

 
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 posted with us 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

___________
(1)
As of December 31, 2013 and 2012, we had cash equivalents of $889 million and $1,274 million included in cash and cash equivalents and $245 million and $228 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
At December 31, 2013, the derivative instruments classified as level 3 primarily included two commodity contracts which are classified as level 3 because the contract terms relate to a delivery location for which observable market rate information is not available, as well as financial power congestion products which settle on the price differential between two power delivery locations, at least one of which is also deemed unobservable. 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, 2013 and 2012:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
December 31, 2013
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
7

 
Discounted cash flow
 
Market price (per MWh)
 
$28.92 — $53.15/MWh
Power Congestion Products
 
$
7

 
Discounted cash flow
 
Market price (per MWh)
 
$(8.79) — $11.53/MWh
 
 
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

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, 2013, 2012 and 2011 (in millions):
 
2013
 
2012
 
2011
Balance, beginning of period
$
16

 
$
17

 
$
30

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

 
8

 
5

Included in fuel and purchased energy expense(2)
—

 
—

 
—

Included in OCI
—

 
—

 
2

Purchases, issuances and settlements:
 
 
 
 
 
Purchases
6

 
3

 
—

Issuances
(2
)
 
(1
)
 
—

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

 
—

 
(2
)
Transfers out of level 3(5)
—

 
—

 
—

Balance, end of period
$
14

 
$
16

 
$
17

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

 
$
8

 
$
5

___________
(1)
For power contracts and other power-related products, 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 transfers into or out of level 1 during the years ended December 31, 2013, 2012 and 2011.
(4)
There were no transfers out of level 2 into level 3 for the years ended December 31, 2013 and 2012. 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, 2013, 2012 and 2011.
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, environmental products 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, 2013, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 10 years.
As of December 31, 2013 and 2012, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
2013
 
2012
Power (MWh)
 
(29
)
 
(16
)
Natural gas (MMBtu)
 
448

 
66

Interest rate swaps
 
$
1,527

 
$
1,602


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, 2013, was $8 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 no additional collateral 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 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, interest rate and environmental product 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 and environmental product 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 — On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and recorded 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
During the first quarter of 2012, we de-designated our remaining commodity derivative cash flow hedges; therefore, as of December 31, 2013 and 2012, we do not have any designated commodity derivative cash flow hedges. 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, 2013 and 2012 (in millions):
 
December 31, 2013
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
445

 
$
—

 
$
445

Long-term derivative assets
96

 
9

 
105

Total derivative assets
$
541

 
$
9

 
$
550

 
 
 
 
 
 
Current derivative liabilities
$
404

 
$
47

 
$
451

Long-term derivative liabilities
161

 
82

 
243

Total derivative liabilities
$
565

 
$
129

 
$
694

Net derivative assets (liabilities)
$
(24
)
 
$
(120
)
 
$
(144
)

 
December 31, 2012
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
339

 
$
—

 
$
339

Long-term derivative assets
94

 
4

 
98

Total derivative assets
$
433

 
$
4

 
$
437

 
 
 
 
 
 
Current derivative liabilities
$
317

 
$
40

 
$
357

Long-term derivative liabilities
133

 
160

 
293

Total derivative liabilities
$
450

 
$
200

 
$
650

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

 
 
December 31, 2013
 
December 31, 2012
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$
9

 
$
115

 
$
4

 
$
184

Total derivatives designated as cash flow hedging instruments
$
9

 
$
115

 
$
4

 
$
184

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
541

 
$
565

 
$
433

 
$
450

Interest rate swaps
—

 
14

 
—

 
16

Total derivatives not designated as hedging instruments
$
541

 
$
579

 
$
433

 
$
466

Total derivatives
$
550

 
$
694

 
$
437

 
$
650


We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at December 31, 2013 and 2012 (in millions):
 
 
December 31, 2013
 
 
Gross Amounts Not Offset on the Consolidated Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
434

 
$
(420
)
 
$
(14
)
 
$
—

Commodity forward contracts
 
107

 
(60
)
 
—

 
47

Interest rate swaps
 
9

 
—

 
—

 
9

Total derivative assets
 
$
550

 
$
(480
)
 
$
(14
)
 
$
56

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(495
)
 
$
420

 
$
75

 
$
—

Commodity forward contracts
 
(70
)
 
60

 
1

 
(9
)
Interest rate swaps
 
(129
)
 
—

 
—

 
(129
)
Total derivative (liabilities)
 
$
(694
)
 
$
480

 
$
76

 
$
(138
)
Net derivative assets (liabilities)
 
$
(144
)
 
$
—

 
$
62

 
$
(82
)
 
 
December 31, 2012
 
 
Gross Amounts Not Offset on the Consolidated Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
385

 
$
(379
)
 
$
(6
)
 
$
—

Commodity forward contracts
 
48

 
(17
)
 
(1
)
 
30

Interest rate swaps
 
4

 
—

 
—

 
4

Total derivative assets
 
$
437

 
$
(396
)
 
$
(7
)
 
$
34

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(424
)
 
$
379

 
$
45

 
$
—

Commodity forward contracts
 
(26
)
 
17

 
1

 
(8
)
Interest rate swaps
 
(200
)
 
—

 
—

 
(200
)
Total derivative (liabilities)
 
$
(650
)
 
$
396

 
$
46

 
$
(208
)
Net derivative assets (liabilities)
 
$
(213
)
 
$
—

 
$
39

 
$
(174
)
____________
(1)
Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 9 for a further discussion of our collateral.
Derivatives Included on Our Consolidated Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Statements of Operations as a component of unrealized mark-to-market activity within 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, 2013, 2012 and 2011 (in millions):
 
2013
 
2012
 
2011
Realized gain (loss)(1)
 
 
 
 
 
Commodity derivative instruments
$
86

 
$
387

 
$
143

Interest rate swaps
—

 
(157
)
 
(193
)
Total realized gain (loss)
$
86

 
$
230

 
$
(50
)
 
 
 
 
 
 
Unrealized gain (loss)(2)
 
 
 
 
 
Commodity derivative instruments
$
(14
)
 
$
(82
)
 
$
(25
)
Interest rate swaps
2

 
154

 
55

Total unrealized gain (loss)
$
(12
)
 
$
72

 
$
30

Total mark-to-market activity, net
$
74

 
$
302

 
$
(20
)
___________
(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 hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
2013
 
2012
 
2011
Realized and unrealized gain (loss)
 
 
 
 
 
Derivatives contracts included in operating revenues
$
(119
)
 
$
187

 
$
(20
)
Derivatives contracts included in fuel and purchased energy expense
191

 
118

 
138

Interest rate swaps included in interest expense
2

 
11

 
7

Loss on interest rate derivatives
—

 
(14
)
 
(145
)
Total mark-to-market activity, net
$
74

 
$
302

 
$
(20
)

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, 2013, 2012 and 2011 (in millions):
 
Gains (Loss) Recognized  in
OCI (Effective Portion)(3)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(4)
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
 
Affected Line Item on the Consolidated Statements of Operations
Commodity derivative instruments(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
Power derivative instruments
$
—

 
$
(97
)
 
$
(99
)
 
$
—

 
$
118

 
$
236

 
Commodity revenue
Natural gas derivative instruments
—

 
59

 
28

 
—

 
(66
)
 
(73
)
 
Commodity expense
Interest rate swaps(2)
86

 
(43
)
 
(23
)
 
(51
)
(5) 
(32
)
 
(47
)
(6) 
Interest expense
Interest rate swaps
—

 
—

 
—

 
—

 
—

 
(91
)
(6) 
Loss on interest rate derivatives
Total(3)
$
86

 
$
(81
)
 
$
(94
)
 
$
(51
)
 
$
20

 
$
25

 
 
____________
(1)
There were no commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2013. We recorded a gain on hedge ineffectiveness of $2 million and a loss of $2 million related to our commodity derivative instruments designated as cash flow hedges during the years ended December 31, 2012 and 2011, respectively.
(2)
We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the years ended December 31, 2013 and 2012. We recorded a loss of $1 million on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges for the year ended December 31, 2011.
(3)
We recorded income tax expense of $3 million for the year ended December 31, 2013, and an income tax benefit of $11 million and $44 million for the years ended December 31, 2012 and 2011, respectively, in AOCI related to our cash flow hedging activities.
(4)
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $148 million, $222 million and $158 million at December 31, 2013, 2012 and 2011, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million, $20 million and $14 million at December 31, 2013, 2012 and 2011, respectively.
(5)
Includes a loss of $12 million that was reclassified from AOCI to interest expense for the year ended December 31, 2013 where the hedged transactions are no longer expected to occur.
(6)
Includes a loss of $15 million and $91 million that was reclassified from AOCI to interest expense and loss on interest rate derivatives, respectively, for the year ended December 31, 2011 where the hedged transactions are no longer expected to occur.
We estimate that pre-tax net losses of $43 million would be reclassified from AOCI into interest expense 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, 2013 and 2012 (in millions):
 
2013
 
2012
Margin deposits(1)
$
261

 
$
196

Natural gas and power prepayments
28

 
35

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
289

 
$
231

 
 
 
 
Letters of credit issued
$
488

 
$
484

First priority liens under power and natural gas agreements
31

 
14

First priority liens under interest rate swap agreements
132

 
206

Total letters of credit and first priority liens with our counterparties
$
651

 
$
704

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
5

 
$
11

Letters of credit posted with us by our counterparties
2

 
1

Total margin deposits and letters of credit posted with us by our counterparties
$
7

 
$
12

___________
(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, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At December 31, 2013 and 2012, $272 million and $211 million, respectively, were included in margin deposits and other prepaid expense and $17 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, 2013, 2012 and 2011, are as follows (in millions):
 
2013
 
2012
 
2011
U.S.
$
(13
)
 
$
194

 
$
(232
)
International
29

 
24

 
20

Total
$
16

 
$
218

 
$
(212
)

The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2013, 2012 and 2011, consisted of the following (in millions):
 
2013
 
2012
 
2011
Current:
 
 
 
 
 
Federal
$
(2
)
 
$
(12
)
 
$
(16
)
State
(9
)
 
16

 
12

Foreign
(1
)
 
14

 
3

Total current
(12
)
 
18

 
(1
)
Deferred:
 
 
 
 
 
Federal
1

 
11

 
(33
)
State
4

 
(5
)
 
9

Foreign
9

 
(5
)
 
3

Total deferred
14

 
1

 
(21
)
Total income tax expense (benefit)
$
2

 
$
19

 
$
(22
)

For the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011, is as follows:
 
2013
 
2012
 
2011
Federal statutory tax expense (benefit) rate
35.0
 %
 
35.0
 %
 
(35.0
)%
State tax expense (benefit), net of federal benefit
(69.8
)
 
3.2

 
6.5

Depletion in excess of basis
(14.7
)
 
(0.2
)
 
—

Federal refunds
—

 
(4.7
)
 
—

Valuation allowances against future tax benefits
89.8

 
(30.3
)
 
57.1

Valuation allowance related to reconsolidation of CCFC
—

 
—

 
(36.0
)
Valuation allowance related to foreign taxes
(19.8
)
 
(8.2
)
 
—

Foreign taxes
(10.8
)
 
3.7

 
(0.9
)
Bankruptcy settlement
—

 
—

 
(15.7
)
Intraperiod allocation
4.5

 
4.6

 
19.9

Change in unrecognized tax benefits
(30.1
)
 
5.1

 
(6.6
)
Disallowed compensation
11.7

 
0.4

 
0.3

Stock-based compensation
8.6

 
0.2

 
0.1

Lobbying contributions
3.3

 
0.3

 
0.4

Other differences
4.8

 
(0.4
)
 
(0.5
)
Effective income tax expense (benefit) rate
12.5
 %
 
8.7
 %
 
(10.4
)%

Deferred Tax Assets and Liabilities
The components of deferred income taxes as of December 31, 2013 and 2012, are as follows (in millions):
 
2013
 
2012
Deferred tax assets:
 
 
 
NOL and credit carryforwards
$
3,120

 
$
3,073

Taxes related to risk management activities and derivatives
60

 
90

Reorganization items and impairments
262

 
315

Foreign capital losses
18

 
25

Other differences
104

 
60

Deferred tax assets before valuation allowance
3,564

 
3,563

Valuation allowance
(2,246
)
 
(2,222
)
Total deferred tax assets
1,318

 
1,341

Deferred tax liabilities: property, plant and equipment
(1,310
)
 
(1,316
)
Net deferred tax asset
8

 
25

Less: Current portion deferred tax asset (liability)
12

 
(3
)
Less: Non-current deferred tax asset
7

 
28

Deferred income tax liability, non-current
$
(11
)
 
$
—


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.
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) with a partial offsetting amount recognized in OCI. The following table details the effects of our intraperiod tax allocations for the years ended December 31, 2013, 2012 and 2011 (in millions).
 
2013
 
2012
 
2011
Intraperiod tax allocation expense included in continuing operations
$
1

 
$
9

 
$
42

Intraperiod tax allocation benefit included in OCI
$
(1
)
 
$
(9
)
 
$
(45
)
NOL Carryforwards — Our NOL carryforwards consist primarily of federal NOL carryforwards of approximately $7.5 billion, which expire between 2023 and 2033, and NOL carryforwards in 33 states and the District of Columbia totaling approximately $4.1 billion, which expire between 2014 and 2033, substantially all of which are offset with a full valuation allowance. We also have approximately $900 million in foreign NOLs, which expire between 2026 and 2033, substantially all of which are offset with a full valuation allowance. 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. If a subsequent ownership change were to occur as a result of future transactions in our stock, accompanied by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited.
Deferred tax assets relating to tax benefits of employee stock-based compensation do not reflect stock options exercised and restricted stock that vested between 2011 and 2013. 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 NOL 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 for the years ended December 31, 2013 and 2012 due to NOL carryforwards, these “windfall” tax benefits are not reflected in our NOLs in deferred tax assets at December 31, 2013 and 2012. The cumulative windfall balance included in federal and state NOL carryforwards, but not reflected in gross deferred tax assets as of December 31, 2013 and 2012 were $25 million and $9 million for federal, respectively, and $16 million and $7 million for state, respectively.
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 periodic audits and reviews by taxing authorities; however, we do not expect these audits 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 January 2013, we received an adjusted reassessment on one of two transfer pricing issues that we are disputing with the Canadian Revenue Authority (“CRA”). We proposed a settlement of the adjusted reassessment with the CRA and it has accepted our proposal. The adjustment to our transfer pricing increased taxable income and was offset by existing NOLs to which a valuation allowance had been applied.

On January 28, 2014, we received a letter from the CRA which informed us that they do not agree with our transfer price on the second issue and will be proposing an increase to taxable income for tax years 2006 and 2007. We continue to believe that our transfer pricing positions and policies are appropriate, and we intend to vigorously defend our position and challenge the CRA’s adjustments, including but not limited to appeal and litigation. If we are unsuccessful in our challenge, any adjustment to Canadian taxable income would first be offset against the existing NOLs that are available. If our existing Canadian NOL’s are not sufficient to offset the resulting adjustment to taxable income, additional assessments, including penalties and interest, would not 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, 2013, 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 increase of $24 million for the year ended December 31, 2013, and a decrease of $114 million and $50 million for the years ended December 31, 2012 and 2011, respectively; all primarily related to changes in our estimates of our ability to utilize our NOL carryforwards.
As a result of a recent favorable response to an IRS letter ruling request, during the first quarter of 2014, we expect to make an election which will increase the tax basis of certain assets resulting in an increase to our net state deferred tax assets by approximately $18 million with a corresponding decrease in our state income tax expense.            
Tangible Property Regulations — On September 13, 2013, the United States Treasury Department and the IRS issued final regulations providing comprehensive guidance on the tax treatment of costs incurred to acquire, repair or improve tangible property. The final regulations are generally effective for taxable years beginning on or after January 1, 2014. On January 24, 2014, the IRS issued procedural guidance pursuant to which taxpayers will be granted automatic consent to change their tax accounting methods to comply with the final regulations. We are currently assessing the future impact of these regulations, but do not anticipate a material impact on our financial condition, results of operations or cash flows.
Unrecognized Tax Benefits
At December 31, 2013, we had unrecognized tax benefits of $68 million. If recognized, $19 million of our unrecognized tax benefits could impact the annual effective tax rate and $49 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We had accrued interest and penalties of $13 million and $24 million for income tax matters at December 31, 2013 and 2012, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Statements of Operations and recorded $(11) million, $4 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2013, 2012 and 2011, is as follows (in millions):
 
2013
 
2012
 
2011
Balance, beginning of period
$
(92
)
 
$
(74
)
 
$
(88
)
Increases related to prior year tax positions
(7
)
 
(19
)
 
—

Decreases related to prior year tax positions
8

 
1

 
1

Decreases related to settlements
10

 
—

 
—

Decrease related to lapse of statute of limitations
13

 
—

 
13

Balance, end of period
$
(68
)
 
$
(92
)
 
$
(74
)

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
We 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, 2013, 2012 and 2011, are as follows (shares in thousands):
 
2013
 
2012
 
2011
Diluted weighted average shares calculation:
 
 
 
 
 
Weighted average shares outstanding (basic)
440,666

 
467,752

 
485,381

Share-based awards
4,107

 
3,591

 
—

Weighted average shares outstanding (diluted)
444,773

 
471,343

 
485,381


We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2013, 2012 and 2011, because they were anti-dilutive (shares in thousands):
 
2013
 
2012
 
2011
Share-based awards
5,062

 
10,302

 
15,260

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 awards 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, 2013, there were 567,000 and 40,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively.
Equity Classified Share-Based Awards
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 for our equity classified share-based awards was $34 million, $25 million and $24 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011. At December 31, 2013, there was unrecognized compensation cost of $1 million related to options, $26 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 0.7 years for options, 1.1 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, 2013, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2012
17,862,501

 
$
17.30

 
4.0
 
$
42

Granted
11,299

 
$
18.34

 
 
 
 
Exercised
3,724,411

 
$
13.70

 
 
 
 
Forfeited
—

 
$
—

 
 
 
 
Expired
35,100

 
$
17.69

 
 
 
 
Outstanding — December 31, 2013
14,114,289

 
$
18.25

 
3.1
 
$
36

Exercisable — December 31, 2013
12,475,493

 
$
18.70

 
2.5
 
$
29

Vested and expected to vest – December 31, 2013
14,038,217

 
$
18.27

 
3.1
 
$
36


The total intrinsic value of our employee stock options exercised was $22 million, $1 million and nil for the years ended December 31, 2013, 2012 and 2011, respectively. The total cash proceeds received from our employee stock options exercised was $20 million, $5 million and nil for the years ended December 31, 2013, 2012 and 2011, respectively.
The fair value of options granted during the years ended December 31, 2013, 2012 and 2011, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
2013
 
2012
 
2011
 
Expected term (in years)(1)
6.5

 
6.5

 
6.5

 
Risk-free interest rate(2)
1.4

%
1.2 – 1.6

%
1.7 – 3.2

%
Expected volatility(3)
25.6

%
27.0 – 30.5

%
31.2 – 44.9

%
Dividend yield(4)
—

 
—

 
—

 
Weighted average grant-date fair value (per option)
$
5.31

 
$
5.18

 
$
5.49

 
___________
(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, 2013, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2012
4,134,037

 
$
14.33

Granted
1,790,448

 
$
18.47

Forfeited
182,438

 
$
16.17

Vested
1,310,206

 
$
12.57

Nonvested — December 31, 2013
4,431,841

 
$
16.45


The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2013, 2012 and 2011, was approximately $25 million, $20 million and $7 million, respectively.
Liability Classified Share-Based Awards
In February 2013, our Board of Directors approved the aggregate award of 449,798 performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2013 through December 31, 2015 compared with the TSR performance of the S&P 500 companies over the same period. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. The performance share units had a grant date fair value of $21.25 and stock-based compensation expense recognized related to these awards was $2 million for the year ended December 31, 2013
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, $12 million and $10 million for the years ended December 31, 2013, 2012 and 2011, 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.
We also maintain a defined benefit pension plan whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. As of December 31, 2013 and 2012, our pension assets, liabilities and related costs were not material to us. As of December 31, 2013 and 2012, there were approximately $14 million and $12 million in plan assets and approximately $20 million and $21 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2013 and 2012, was approximately $6 million and $9 million, respectively. For the years ended December 31, 2013, 2012 and 2011, we recognized net periodic benefit costs of approximately $2 million, $1 million and $1 million, respectively. Our net periodic benefit cost is included in plant operating expense on our Consolidated Statements of Operations. As of December 31, 2013 and 2012, the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $1 million and $5 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 2013 and 2012, we made contributions of approximately $1 million and $2 million, respectively, and estimated contributions to the pension plan are expected to be approximately $2 million in 2014. 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, 2013 and 2012, was 497,841,056 shares and 492,495,100 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2013 and 2012, was 429,038,988 shares and 457,048,970 shares, respectively. The table below summarizes our common stock activity for the years ended December 31, 2013, 2012 and 2011.
 
Shares
Issued
 
Shares
Held in
Treasury
 
Shares
Held in
Reserve
 
Total
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

Shares issued under Calpine Equity Incentive Plans
5,345,956

 
(2,323,828
)
 
—

 
3,022,128

Share repurchase program
—

 
(31,032,110
)
 
—

 
(31,032,110
)
Balance, December 31, 2013
497,841,056

 
(68,802,068
)
 
—

 
429,038,988


Treasury Stock
As of December 31, 2013 and 2012, we had treasury stock of 68,802,068 shares and 35,446,130 shares, respectively, with a cost of $1.2 billion and $594 million, respectively. Having previously authorized $600 million in repurchases of our common stock, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock in February 2013 and an additional $100 million in August 2013. Under the aggregate $1.1 billion of authorizations, we repurchased a total of 60,139,816 shares of our outstanding common stock at an average price of $18.29 per share. In November 2013, our Board of Directors authorized a new $1.0 billion multi-year share repurchase program, under which we have repurchased a total of 12,459,919 shares of our common stock for approximately $239 million at an average price of $19.15 per share as of the filing of this Report. 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 and net share employee stock options exercises under the Equity Plan. All treasury stock is held at cost.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
Long-Term Service Agreements
As of December 31, 2013, the total estimated commitments for LTSAs associated with turbines installed or in storage were approximately $134 million. These commitments are payable over the terms of the respective agreements, which range from 1 to 12 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 rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
 
Initial
Year
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
Land and other operating leases
various
 
$
15

 
$
15

 
$
15

 
$
15

 
$
15

 
$
215

 
$
290

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
4

 
$
—

 
$
—

 
$
—

 
$
—

 
$
11

KIAC
2000
 
24

 
23

 
22

 
22

 
22

 
30

 
143

Total power plant leases
 
 
$
31

 
$
27

 
$
22

 
$
22

 
$
22

 
$
30

 
$
154

Total leases
 
 
$
46

 
$
42

 
$
37

 
$
37

 
$
37

 
$
245

 
$
444


During the years ended December 31, 2013, 2012 and 2011, rent expense for power plant and land and other operating leases amounted to $47 million, $51 million and $53 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, 2013, 2012 and 2011, were $27 million, $22 million and $22 million, respectively.
Office Leases
We lease our corporate and regional offices under noncancelable operating leases extending through 2020. Future minimum lease payments under these leases are as follows (in millions):
2014
$
11

2015
10

2016
10

2017
11

2018
10

Thereafter
28

Total
$
80


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, 2013, 2012 and 2011, rent expense for noncancelable operating leases was $12 million, $12 million and $13 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. These contracts are accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet. At December 31, 2013, we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions):
2014
$
385

2015
290

2016
238

2017
235

2018
224

Thereafter
815

Total
$
2,187


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, 2013, 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
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
Guarantee of subsidiary debt(1)
 
$
36

 
$
37

 
$
36

 
$
26

 
$
31

 
$
178

 
$
344

Standby letters of credit(2)(4)
 
562

 
11

 
—

 
20

 
—

 
37

 
630

Surety bonds(3)(4)(5)
 
—

 
—

 
—

 
—

 
—

 
27

 
27

 Guarantee of subsidiary operating lease payments(4)
 
7

 
4

 
—

 
—

 
—

 
—

 
11

Total
 
$
605

 
$
52

 
$
36

 
$
46

 
$
31

 
$
242

 
$
1,012

____________
(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, 2013, $4 million of cash collateral is outstanding related to these bonds.
We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of our subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of our partially-owned subsidiaries up to our ownership percentage. The letters of credit issued under various credit facilities support CES risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to ten days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included on our Consolidated Balance Sheets.
Commercial Agreements — In connection with the purchase and sale of power, natural gas and emission allowances to and from third parties with respect to the operation of our power plants, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. These guarantees may include future payment obligations 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, warranty or covenant 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, maintenance and service agreements and equipment lease agreements. These guarantee and indemnification obligations may include indemnification from personal injury or other claims by our employees as well as 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, 2013, there are no material 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, 2013, 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, 2013
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,937

 
$
2,347

 
$
1,356

 
$
661

 
$
—

 
$
6,301

Intersegment revenues
5

 
(4
)
 
33

 
189

 
(223
)
 
—

Total operating revenues
$
1,942

 
$
2,343

 
$
1,389

 
$
850

 
$
(223
)
 
$
6,301

Commodity Margin
$
1,020

 
$
632

 
$
712

 
$
204

 
$
—

 
$
2,568

Add: Unrealized mark-to-market commodity activity, net and other(1)
(50
)
 
51

 
5

 
22

 
(31
)
 
(3
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
365

 
269

 
172

 
120

 
(31
)
 
895

Depreciation and amortization expense
243

 
165

 
130

 
73

 
(2
)
 
609

Sales, general and other administrative expense
37

 
56

 
21

 
21

 
1

 
136

Other operating expenses
45

 
3

 
29

 
4

 
—

 
81

(Income) from unconsolidated investments in power plants
—

 
—

 
(30
)
 
—

 
—

 
(30
)
Income from operations
280

 
190

 
395

 
8

 
1

 
874

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
690

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
164

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
20


 
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(2)(3)
$
994

 
$
570

 
$
729

 
$
245

 
$
—

 
$
2,538

Add: Unrealized mark-to-market commodity activity, net and other(1)
(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
 
 
 
 
 
 
 
 
 
 
$
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(2)(3)
$
1,061

 
$
469

 
$
704

 
$
240

 
$
—

 
$
2,474

Add: Unrealized mark-to-market commodity activity, net and other(1)
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
 
 
 
 
 
 
 
 
 
 
$
(211
)
__________
(1)
Includes $6 million, $1 million and $12 million of lease levelization and $14 million, $14 million and $8 million of amortization expense for the years ended December 31, 2013, 2012 and 2011, respectively.
(2)
Our North segment includes Commodity Margin of $73 million and $70 million for the years ended December 31, 2012 and 2011, respectively, related to Riverside Energy Center, LLC, which was sold in December 2012.
(3)
Our Southeast segment includes Commodity Margin of $52 million and $51 million for the years ended December 31, 2012 and 2011, respectively, related to Broad River, which was sold in December 2012.
Significant Customers
For the year ended December 31, 2013, we had two significant customers that individually accounted for more than 10% of our annual consolidated revenues, PJM Settlement, Inc. and PG&E. For the years ended December 31, 2012 and 2011, we only had one significant customer that individually accounted for more than 10% of our annual consolidated revenues, PJM Settlement, Inc. Our revenues from PJM Settlement, Inc. for the years ended December 31, 2013, 2012 and 2011 were approximately $820 million, $713 million and $742 million, respectively, and were attributed to our North segment. Our revenues from PG&E were approximately $694 million for the year ended December 31, 2013 and were attributed to our West segment. As of December 31, 2013 and 2012, our receivables from PJM Settlement, Inc. were approximately $26 million and $37 million, respectively. As of December 31, 2013, our receivables from PG&E were approximately $83 million.
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)
2013
 
 
 
 
 
 
 
Operating revenues
$
1,438

 
$
2,050

 
$
1,572

 
$
1,241

Income from operations
$
151

 
$
597

 
$
122

 
$
4

Net income (loss) attributable to Calpine
$
(97
)
 
$
306

 
$
(70
)
 
$
(125
)
Net income (loss) per common share attributable to Calpine — Basic
$
(0.23
)
 
$
0.70

 
$
(0.16
)
 
$
(0.28
)
Net income (loss) per common share attributable to Calpine — Diluted
$
(0.23
)
 
$
0.70

 
$
(0.16
)
 
$
(0.28
)
 
 
 
 
 
 
 
 
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
)
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, 2013
 
 
 
 
 
 
 
 
 
Allowance for doubtful accounts
$
6

 
$
4

 
$
(5
)
 
$
—

 
$
5

Deferred tax asset valuation allowance
2,222

 
24

 
—

 
—

 
2,246

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

_____________
(1)
Represents write-offs of accounts considered to be uncollectible and previously reserved.
Summary of Significant Accounting Policies (Policies)
Commitments and Contingencies, Policy [Policy Text Block] 
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.
Reclassification 
Reclassifications — Certain reclassifications have been made to our Consolidated Balance Sheet as of December 31, 2012, and our Statements of Comprehensive Income (Loss), Stockholders' Equity and Cash Flows for the years ended December 31, 2012 and 2011, to conform to the current year presentation. Our reclassifications are summarized as follows:
•
We have reclassified $(6) million and $(14) million related to our noncontrolling interest's portion of cash flow hedge losses, net of tax, in OCI to comprehensive income (loss) attributable to the noncontrolling interest for the years ended December 31, 2012 and 2011, respectively, on our Consolidated Statements of Comprehensive Income (Loss). This reclassification is also reflected in the AOCI and noncontrolling interest balances on our Consolidated Balance Sheet as of December 31, 2012 and on our Consolidated Statements of Stockholders' Equity for the years ended December 31, 2012 and 2011.
•
We have reclassified $5 million and nil on our Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011, respectively, to separately report proceeds from the exercises of stock options, previously reflected in other cash flows used in financing activities.
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 
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.
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 Note 7 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, 2013 and 2012, we had cash and cash equivalents of $292 million and $131 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash 
Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.
Accounts Receivable and Payable 
Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance accounts after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.
The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.
Inventory 
At December 31, 2013 and 2012, we had inventory of $364 million and $301 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental products 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, certain replacements or repairs when the repairs 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 power plant or have a favorable option to purchase the power plant or take ownership of the power plant 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 2013, 2012 and 2011, we did not record any material impairment losses.
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, 2013 and 2012, our asset retirement obligation liabilities were $44 million and $38 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.
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 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 natural gas transactions economically hedging anticipated future power sales that 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.
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.
Summary of Significant Accounting Policies (Tables)
Schedule of Jointly Owned Utility Plants [Table Text Block] 
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, 2013
 
Ownership Interest
 
Property, Plant & Equipment
 
Accumulated Depreciation
 
Construction in Progress
(in millions, except percentages)
Freestone Energy Center
 
75.0
%
 
$
393

 
$
(135
)
 
$
—

Hidalgo Energy Center
 
78.5
%
 
$
255

 
$
(93
)
 
$
—

Schedule of Components of 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, 2013 and 2012 (in millions):
 
 
2013
 
2012
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
11

 
$
41

 
$
52

 
$
11

 
$
41

 
$
52

Rent reserve
3

 
—

 
3

 
—

 
—

 
—

Construction/major maintenance
35

 
20

 
55

 
32

 
14

 
46

Security/project/insurance
151

 
6

 
157

 
101

 
3

 
104

Other
3

 
2

 
5

 
49

 
2

 
51

Total
$
203

 
$
69

 
$
272

 
$
193

 
$
60

 
$
253

___________
(1)
At December 31, 2013 and 2012, amounts restricted for debt service included approximately $24 million and $25 million, respectively, of repurchase agreements with a financial institution containing maturity dates greater than one year.
Schedule of Total Contractual Future Minimum Lease Receipts 
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 at December 31, 2013, are as follows (in millions):
2014
$
632

2015
641

2016
582

2017
546

2018
517

Thereafter
2,577

Total
$
5,495

Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
 
Initial
Year
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
Land and other operating leases
various
 
$
15

 
$
15

 
$
15

 
$
15

 
$
15

 
$
215

 
$
290

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
4

 
$
—

 
$
—

 
$
—

 
$
—

 
$
11

KIAC
2000
 
24

 
23

 
22

 
22

 
22

 
30

 
143

Total power plant leases
 
 
$
31

 
$
27

 
$
22

 
$
22

 
$
22

 
$
30

 
$
154

Total leases
 
 
$
46

 
$
42

 
$
37

 
$
37

 
$
37

 
$
245

 
$
444

Property, Plant and Equipment, Net (Tables)
Property, Plant and Equipment
As of December 31, 2013 and 2012, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
2013
 
2012
 
Depreciable Lives
Buildings, machinery and equipment(1)
$
15,838

 
$
14,774

 
3 – 47 Years
Geothermal properties
1,265

 
1,243

 
13 – 59 Years
Other
164

 
142

 
3 – 47 Years
 
17,267

 
16,159

 
 
Less: Accumulated depreciation
4,897

 
4,390

 
 
 
12,370

 
11,769

 
 
Land
103

 
98

 
 
Construction in progress(1)
522

 
1,138

 
 
Property, plant and equipment, net
$
12,995

 
$
13,005

 
 

___________
(1)
The change from December 31, 2012 to December 31, 2013 is primarily attributed to our Russell City and Los Esteros power plants commencing commercial operations during 2013.
Variable Interest Entities and Unconsolidated Investments (Tables)
Schedule of Condensed Financial Statements 
Aggregated summarized financial data for our unconsolidated subsidiaries is set forth below (in millions):
Condensed Combined Balance Sheets
of Our Unconsolidated Subsidiaries
December 31, 2013 and 2012

 
2013
 
2012
Assets:
 
 
 
Cash and cash equivalents
$
57

 
$
64

Current assets
25

 
30

Property, plant and equipment, net
588

 
648

Other assets
2

 
4

Total assets
$
672

 
$
746

Liabilities:
 
 
 
Current maturities of long-term debt
$
23

 
$
25

Current liabilities
44

 
36

Long-term debt
372

 
423

Long-term derivative liabilities
35

 
84

Total liabilities
474

 
568

Member's interest
198

 
178

Total liabilities and member's interest
$
672

 
$
746


Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
For the Years Ended December 31, 2013, 2012 and 2011

 
2013
 
2012
 
2011
Revenues
$
207

 
$
247

 
$
277

Operating expenses
128

 
171

 
208

Income from operations
79

 
76

 
69

Interest expense, net of interest income
24

 
27

 
30

Other (income) expense, net
(3
)
 
(2
)
 
2

Net income
$
58

 
$
51

 
$
37

Schedule of Equity Method Investments 
At December 31, 2013 and 2012, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of December 31, 2013
 
2013
 
2012
Greenfield LP
50%
 
$
76

 
$
69

Whitby
50%
 
17

 
12

Total investments in power plants
 
 
$
93

 
$
81

Income (Loss) From Unconsolidated Investments in Power Plants and Distributions 
Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2013, 2012 and 2011, is 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
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
Greenfield LP
$
(16
)
 
$
(17
)
 
$
(12
)
 
$
18

 
$
22

 
$
2

Whitby
(14
)
 
(11
)
 
(9
)
 
9

 
7

 
4

Total
$
(30
)
 
$
(28
)
 
$
(21
)
 
$
27

 
$
29

 
$
6


Debt (Tables)
Schedule of Long-term Debt Instruments 
Our debt at December 31, 2013 and 2012, was as follows (in millions):
 
2013
 
2012
First Lien Notes
$
4,989

 
$
5,303

First Lien Term Loans
2,828

 
2,463

Project financing, notes payable and other
1,901

 
1,789

CCFC Term Loans
1,191

 
—

CCFC Notes
—

 
978

Capital lease obligations
203

 
217

Subtotal
11,112

 
10,750

Less: Current maturities
204

 
115

Total long-term debt
$
10,908

 
$
10,635

Schedule of Maturities of Long-term Debt 
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2013, are as follows (in millions):
 
2014
$
205

2015
183

2016
194

2017
550

2018
1,717

Thereafter
8,291

Subtotal
11,140

Less: Discount
28

Total debt
$
11,112

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(3)
 
2013
 
2012
 
2013
 
2012
2017 First Lien Notes(1)
$
—

 
$
1,080

 
—
%
 
7.5
%
2019 First Lien Notes(2)
320

 
360

 
8.2

 
8.2

2020 First Lien Notes(2)
875

 
983

 
8.2

 
8.1

2021 First Lien Notes(2)
1,600

 
1,800

 
7.7

 
7.7

2022 First Lien Notes(1)
744

 
—

 
6.2

 
—

2023 First Lien Notes(2)
960

 
1,080

 
8.0

 
8.0

2024 First Lien Notes(2)
490

 
—

 
5.9

 
—

Total First Lien Notes
$
4,989

 
$
5,303

 
 
 
 
____________
(1)
On October 17, 2013, we launched a tender offer to repay our 2017 First Lien Notes with the proceeds from our 2020 First Lien Term Loan and 2022 First Lien Notes which are described in further detail below. On October 31, 2013, following the early tender and consent date of the tender offer, we purchased approximately $742 million in aggregate principal amount of our 2017 First Lien Notes and issued a redemption notice to the remaining holders of our 2017 First Lien Notes that did not tender their notes in the tender offer. The tender offer expired on November 29, 2013 and we purchased the remaining $338 million in aggregate principal amount of our 2017 First Lien Notes tendered prior to the expiration of the tender offer, and redeemed any remaining 2017 First Lien Notes on December 2, 2013.
(2)
On October 31, 2013, we issued $490 million in aggregate principal amount of our 2024 First Lien Notes and used the proceeds to redeem 10% of the original aggregate principal amount of our 2019 First Lien Notes, 2020 First Lien Notes, 2021 First Lien Notes and 2023 First Lien Notes at a redemption price of 103% of the principal amount redeemed, plus accrued and unpaid interest.
(3)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
First Lien Term Loans 
Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates):
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2013
 
2012
 
2013
 
2012
2018 First Lien Term Loans
$
1,614

 
$
1,630

 
4.3
%
 
4.7
%
2019 First Lien Term Loan
824

 
833

 
4.5

 
4.7

2020 First Lien Term Loan
390

 
—

 
4.3

 
—

Total First Lien Term Loans
$
2,828

 
$
2,463

 
 
 
 
____________
(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)
 
2013
 
2012
 
2013
 
2012
Russell City Project Debt due 2023
$
593

 
$
507

 
4.9
%
 
3.6
%
Steamboat due 2017
418

 
428

 
6.8

 
6.8

OMEC due 2019
335

 
345

 
6.9

 
6.8

Los Esteros Project Debt due 2023
305

 
209

 
3.4

 
3.5

Pasadena(2)
135

 
160

 
8.9

 
8.9

Bethpage Energy Center 3 due 2020-2025(3)
88

 
93

 
7.0

 
7.0

Gilroy note payable due 2014
15

 
33

 
11.2

 
10.8

Other
12

 
14

 
—

 
—

Total
$
1,901

 
$
1,789

 
 
 
 
_____________
(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.
CCFC Notes and CCFC Term Loans [Table Text Block] 
Our CCFC Term Loans and CCFC Notes are summarized in the table below (in millions, except for interest rates):
 
Outstanding at December 31,
 
Weighted Average
Effective Interest Rates(1)
 
2013
 
2012
 
2013
 
2012
CCFC Term Loans
$
1,191

 
$
—

 
3.3
%
 
—
%
CCFC Notes
—

 
978

 
—

 
8.9

Total CCFC Term Loans and CCFC Notes
$
1,191

 
$
978

 
 
 
 
____________
(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Schedule of Future Minimum Lease Payments for Capital Leases 
The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the net minimum lease payments as of December 31, 2013 (in millions):
 
Sale-Leaseback Transactions(1)
 
Capital Lease
 
Total
2014
$
25

 
$
51

 
$
76

2015
25

 
38

 
63

2016
25

 
40

 
65

2017
17

 
38

 
55

2018
21

 
37

 
58

Thereafter
106

 
125

 
231

Total minimum lease payments
219

 
329

 
548

Less: Amount representing interest
84

 
126

 
210

Present value of net minimum lease payments
$
135

 
$
203

 
$
338

____________
(1)
Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
Schedule of Line of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at December 31, 2013 and 2012 (in millions):
 
2013
 
2012
Corporate Revolving Facility
$
242

 
$
243

CDHI
218

 
253

Various project financing facilities
170

 
130

Total
$
630

 
$
626

Fair Value, by Balance Sheet Grouping 
The following table details the fair values and carrying values of our debt instruments at December 31, 2013 and 2012 (in millions):
 
2013
 
2012
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
5,317

 
$
4,989

 
$
5,863

 
$
5,303

First Lien Term Loans
2,845

 
2,828

 
2,489

 
2,463

Project financing, notes payable and other(1)
1,772

 
1,766

 
1,599

 
1,629

CCFC Term Loans
1,179

 
1,191

 
—

 
—

CCFC Notes
—

 
—

 
1,075

 
978

Total
$
11,113

 
$
10,774

 
$
11,026

 
$
10,373

____________
(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)
Fair Value Inputs, Assets, Quantitative Information [Table Text Block] 
The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2013 and 2012:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
December 31, 2013
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
7

 
Discounted cash flow
 
Market price (per MWh)
 
$28.92 — $53.15/MWh
Power Congestion Products
 
$
7

 
Discounted cash flow
 
Market price (per MWh)
 
$(8.79) — $11.53/MWh
 
 
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
Fair Value, Measurement Inputs, Disclosure 
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2013
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,134

 
$
—

 
$
—

 
$
1,134

Margin deposits
261

 
—

 
—

 
261

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
434

 
—

 
—

 
434

Commodity forward contracts(2)
—

 
75

 
32

 
107

Interest rate swaps
—

 
9

 
—

 
9

Total assets
$
1,829

 
$
84

 
$
32

 
$
1,945

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
5

 
$
—

 
$
—

 
$
5

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
495

 
—

 
—

 
495

Commodity forward contracts(2)
—

 
52

 
18

 
70

Interest rate swaps
—

 
129

 
—

 
129

Total liabilities
$
500

 
$
181

 
$
18

 
$
699

 
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 posted with us 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

___________
(1)
As of December 31, 2013 and 2012, we had cash equivalents of $889 million and $1,274 million included in cash and cash equivalents and $245 million and $228 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation 
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the years ended December 31, 2013, 2012 and 2011 (in millions):
 
2013
 
2012
 
2011
Balance, beginning of period
$
16

 
$
17

 
$
30

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

 
8

 
5

Included in fuel and purchased energy expense(2)
—

 
—

 
—

Included in OCI
—

 
—

 
2

Purchases, issuances and settlements:
 
 
 
 
 
Purchases
6

 
3

 
—

Issuances
(2
)
 
(1
)
 
—

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

 
—

 
(2
)
Transfers out of level 3(5)
—

 
—

 
—

Balance, end of period
$
14

 
$
16

 
$
17

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

 
$
8

 
$
5

___________
(1)
For power contracts and other power-related products, 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 transfers into or out of level 1 during the years ended December 31, 2013, 2012 and 2011.
(4)
There were no transfers out of level 2 into level 3 for the years ended December 31, 2013 and 2012. 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, 2013, 2012 and 2011.
Derivative Instruments (Tables)
Schedule of Notional Amounts of Outstanding Derivative Positions 
As of December 31, 2013 and 2012, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
2013
 
2012
Power (MWh)
 
(29
)
 
(16
)
Natural gas (MMBtu)
 
448

 
66

Interest rate swaps
 
$
1,527

 
$
1,602

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value 
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2013 and 2012 (in millions):
 
December 31, 2013
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
445

 
$
—

 
$
445

Long-term derivative assets
96

 
9

 
105

Total derivative assets
$
541

 
$
9

 
$
550

 
 
 
 
 
 
Current derivative liabilities
$
404

 
$
47

 
$
451

Long-term derivative liabilities
161

 
82

 
243

Total derivative liabilities
$
565

 
$
129

 
$
694

Net derivative assets (liabilities)
$
(24
)
 
$
(120
)
 
$
(144
)

 
December 31, 2012
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
339

 
$
—

 
$
339

Long-term derivative assets
94

 
4

 
98

Total derivative assets
$
433

 
$
4

 
$
437

 
 
 
 
 
 
Current derivative liabilities
$
317

 
$
40

 
$
357

Long-term derivative liabilities
133

 
160

 
293

Total derivative liabilities
$
450

 
$
200

 
$
650

Net derivative assets (liabilities)
$
(17
)
 
$
(196
)
 
$
(213
)
Derivative Instrument by Accounting Designation 
 
December 31, 2013
 
December 31, 2012
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$
9

 
$
115

 
$
4

 
$
184

Total derivatives designated as cash flow hedging instruments
$
9

 
$
115

 
$
4

 
$
184

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
541

 
$
565

 
$
433

 
$
450

Interest rate swaps
—

 
14

 
—

 
16

Total derivatives not designated as hedging instruments
$
541

 
$
579

 
$
433

 
$
466

Total derivatives
$
550

 
$
694

 
$
437

 
$
650


Offsetting Assets [Table Text Block] 
The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at December 31, 2013 and 2012 (in millions):
 
 
December 31, 2013
 
 
Gross Amounts Not Offset on the Consolidated Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
434

 
$
(420
)
 
$
(14
)
 
$
—

Commodity forward contracts
 
107

 
(60
)
 
—

 
47

Interest rate swaps
 
9

 
—

 
—

 
9

Total derivative assets
 
$
550

 
$
(480
)
 
$
(14
)
 
$
56

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(495
)
 
$
420

 
$
75

 
$
—

Commodity forward contracts
 
(70
)
 
60

 
1

 
(9
)
Interest rate swaps
 
(129
)
 
—

 
—

 
(129
)
Total derivative (liabilities)
 
$
(694
)
 
$
480

 
$
76

 
$
(138
)
Net derivative assets (liabilities)
 
$
(144
)
 
$
—

 
$
62

 
$
(82
)
 
 
December 31, 2012
 
 
Gross Amounts Not Offset on the Consolidated Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
385

 
$
(379
)
 
$
(6
)
 
$
—

Commodity forward contracts
 
48

 
(17
)
 
(1
)
 
30

Interest rate swaps
 
4

 
—

 
—

 
4

Total derivative assets
 
$
437

 
$
(396
)
 
$
(7
)
 
$
34

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(424
)
 
$
379

 
$
45

 
$
—

Commodity forward contracts
 
(26
)
 
17

 
1

 
(8
)
Interest rate swaps
 
(200
)
 
—

 
—

 
(200
)
Total derivative (liabilities)
 
$
(650
)
 
$
396

 
$
46

 
$
(208
)
Net derivative assets (liabilities)
 
$
(213
)
 
$
—

 
$
39

 
$
(174
)
____________
(1)
Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 9 for a further discussion of our collateral.
Realized Unrealized Gain Loss by Instrument 
The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011 (in millions):
 
2013
 
2012
 
2011
Realized gain (loss)(1)
 
 
 
 
 
Commodity derivative instruments
$
86

 
$
387

 
$
143

Interest rate swaps
—

 
(157
)
 
(193
)
Total realized gain (loss)
$
86

 
$
230

 
$
(50
)
 
 
 
 
 
 
Unrealized gain (loss)(2)
 
 
 
 
 
Commodity derivative instruments
$
(14
)
 
$
(82
)
 
$
(25
)
Interest rate swaps
2

 
154

 
55

Total unrealized gain (loss)
$
(12
)
 
$
72

 
$
30

Total mark-to-market activity, net
$
74

 
$
302

 
$
(20
)
___________
(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 hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] 
 
2013
 
2012
 
2011
Realized and unrealized gain (loss)
 
 
 
 
 
Derivatives contracts included in operating revenues
$
(119
)
 
$
187

 
$
(20
)
Derivatives contracts included in fuel and purchased energy expense
191

 
118

 
138

Interest rate swaps included in interest expense
2

 
11

 
7

Loss on interest rate derivatives
—

 
(14
)
 
(145
)
Total mark-to-market activity, net
$
74

 
$
302

 
$
(20
)
Derivatives Designated as Hedges 
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the years ended December 31, 2013, 2012 and 2011 (in millions):
 
Gains (Loss) Recognized  in
OCI (Effective Portion)(3)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(4)
 
2013
 
2012
 
2011
 
2013
 
2012
 
2011
 
Affected Line Item on the Consolidated Statements of Operations
Commodity derivative instruments(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
Power derivative instruments
$
—

 
$
(97
)
 
$
(99
)
 
$
—

 
$
118

 
$
236

 
Commodity revenue
Natural gas derivative instruments
—

 
59

 
28

 
—

 
(66
)
 
(73
)
 
Commodity expense
Interest rate swaps(2)
86

 
(43
)
 
(23
)
 
(51
)
(5) 
(32
)
 
(47
)
(6) 
Interest expense
Interest rate swaps
—

 
—

 
—

 
—

 
—

 
(91
)
(6) 
Loss on interest rate derivatives
Total(3)
$
86

 
$
(81
)
 
$
(94
)
 
$
(51
)
 
$
20

 
$
25

 
 
____________
(1)
There were no commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2013. We recorded a gain on hedge ineffectiveness of $2 million and a loss of $2 million related to our commodity derivative instruments designated as cash flow hedges during the years ended December 31, 2012 and 2011, respectively.
(2)
We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the years ended December 31, 2013 and 2012. We recorded a loss of $1 million on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges for the year ended December 31, 2011.
(3)
We recorded income tax expense of $3 million for the year ended December 31, 2013, and an income tax benefit of $11 million and $44 million for the years ended December 31, 2012 and 2011, respectively, in AOCI related to our cash flow hedging activities.
(4)
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $148 million, $222 million and $158 million at December 31, 2013, 2012 and 2011, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million, $20 million and $14 million at December 31, 2013, 2012 and 2011, respectively.
(5)
Includes a loss of $12 million that was reclassified from AOCI to interest expense for the year ended December 31, 2013 where the hedged transactions are no longer expected to occur.
(6)
Includes a loss of $15 million and $91 million that was reclassified from AOCI to interest expense and loss on interest rate derivatives, respectively, for the year ended December 31, 2011 where the hedged transactions are no longer expected to occur.
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, 2013 and 2012 (in millions):
 
2013
 
2012
Margin deposits(1)
$
261

 
$
196

Natural gas and power prepayments
28

 
35

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
289

 
$
231

 
 
 
 
Letters of credit issued
$
488

 
$
484

First priority liens under power and natural gas agreements
31

 
14

First priority liens under interest rate swap agreements
132

 
206

Total letters of credit and first priority liens with our counterparties
$
651

 
$
704

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
5

 
$
11

Letters of credit posted with us by our counterparties
2

 
1

Total margin deposits and letters of credit posted with us by our counterparties
$
7

 
$
12

___________
(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, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At December 31, 2013 and 2012, $272 million and $211 million, respectively, were included in margin deposits and other prepaid expense and $17 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)
Schedule of Income before Income Tax, Domestic and Foreign 
The jurisdictional components of income (loss) from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2013, 2012 and 2011, are as follows (in millions):
 
2013
 
2012
 
2011
U.S.
$
(13
)
 
$
194

 
$
(232
)
International
29

 
24

 
20

Total
$
16

 
$
218

 
$
(212
)
Schedule of Components of Income Tax Expense (Benefit) 
The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2013, 2012 and 2011, consisted of the following (in millions):
 
2013
 
2012
 
2011
Current:
 
 
 
 
 
Federal
$
(2
)
 
$
(12
)
 
$
(16
)
State
(9
)
 
16

 
12

Foreign
(1
)
 
14

 
3

Total current
(12
)
 
18

 
(1
)
Deferred:
 
 
 
 
 
Federal
1

 
11

 
(33
)
State
4

 
(5
)
 
9

Foreign
9

 
(5
)
 
3

Total deferred
14

 
1

 
(21
)
Total income tax expense (benefit)
$
2

 
$
19

 
$
(22
)

Schedule of Effective Income Tax Rate Reconciliation 
A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2013, 2012 and 2011, is as follows:
 
2013
 
2012
 
2011
Federal statutory tax expense (benefit) rate
35.0
 %
 
35.0
 %
 
(35.0
)%
State tax expense (benefit), net of federal benefit
(69.8
)
 
3.2

 
6.5

Depletion in excess of basis
(14.7
)
 
(0.2
)
 
—

Federal refunds
—

 
(4.7
)
 
—

Valuation allowances against future tax benefits
89.8

 
(30.3
)
 
57.1

Valuation allowance related to reconsolidation of CCFC
—

 
—

 
(36.0
)
Valuation allowance related to foreign taxes
(19.8
)
 
(8.2
)
 
—

Foreign taxes
(10.8
)
 
3.7

 
(0.9
)
Bankruptcy settlement
—

 
—

 
(15.7
)
Intraperiod allocation
4.5

 
4.6

 
19.9

Change in unrecognized tax benefits
(30.1
)
 
5.1

 
(6.6
)
Disallowed compensation
11.7

 
0.4

 
0.3

Stock-based compensation
8.6

 
0.2

 
0.1

Lobbying contributions
3.3

 
0.3

 
0.4

Other differences
4.8

 
(0.4
)
 
(0.5
)
Effective income tax expense (benefit) rate
12.5
 %
 
8.7
 %
 
(10.4
)%
Schedule of Deferred Tax Assets and Liabilities 
The components of deferred income taxes as of December 31, 2013 and 2012, are as follows (in millions):
 
2013
 
2012
Deferred tax assets:
 
 
 
NOL and credit carryforwards
$
3,120

 
$
3,073

Taxes related to risk management activities and derivatives
60

 
90

Reorganization items and impairments
262

 
315

Foreign capital losses
18

 
25

Other differences
104

 
60

Deferred tax assets before valuation allowance
3,564

 
3,563

Valuation allowance
(2,246
)
 
(2,222
)
Total deferred tax assets
1,318

 
1,341

Deferred tax liabilities: property, plant and equipment
(1,310
)
 
(1,316
)
Net deferred tax asset
8

 
25

Less: Current portion deferred tax asset (liability)
12

 
(3
)
Less: Non-current deferred tax asset
7

 
28

Deferred income tax liability, non-current
$
(11
)
 
$
—

Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation 
The following table details the effects of our intraperiod tax allocations for the years ended December 31, 2013, 2012 and 2011 (in millions).
 
2013
 
2012
 
2011
Intraperiod tax allocation expense included in continuing operations
$
1

 
$
9

 
$
42

Intraperiod tax allocation benefit included in OCI
$
(1
)
 
$
(9
)
 
$
(45
)
Schedule of Income Tax Contingencies 
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2013, 2012 and 2011, is as follows (in millions):
 
2013
 
2012
 
2011
Balance, beginning of period
$
(92
)
 
$
(74
)
 
$
(88
)
Increases related to prior year tax positions
(7
)
 
(19
)
 
—

Decreases related to prior year tax positions
8

 
1

 
1

Decreases related to settlements
10

 
—

 
—

Decrease related to lapse of statute of limitations
13

 
—

 
13

Balance, end of period
$
(68
)
 
$
(92
)
 
$
(74
)
Earnings (Loss) per Share (Tables)
Schedule of Weighted Average Number of Shares 
Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the years ended December 31, 2013, 2012 and 2011, are as follows (shares in thousands):
 
2013
 
2012
 
2011
Diluted weighted average shares calculation:
 
 
 
 
 
Weighted average shares outstanding (basic)
440,666

 
467,752

 
485,381

Share-based awards
4,107

 
3,591

 
—

Weighted average shares outstanding (diluted)
444,773

 
471,343

 
485,381

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share 
We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2013, 2012 and 2011, because they were anti-dilutive (shares in thousands):
 
2013
 
2012
 
2011
Share-based awards
5,062

 
10,302

 
15,260

Stock-Based Compensation (Tables)
Schedule of Non-Qualified Stock Option Activity 
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2013, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2012
17,862,501

 
$
17.30

 
4.0
 
$
42

Granted
11,299

 
$
18.34

 
 
 
 
Exercised
3,724,411

 
$
13.70

 
 
 
 
Forfeited
—

 
$
—

 
 
 
 
Expired
35,100

 
$
17.69

 
 
 
 
Outstanding — December 31, 2013
14,114,289

 
$
18.25

 
3.1
 
$
36

Exercisable — December 31, 2013
12,475,493

 
$
18.70

 
2.5
 
$
29

Vested and expected to vest – December 31, 2013
14,038,217

 
$
18.27

 
3.1
 
$
36

Schedule of Assumptions Used to Estimate Fair Value for Options 
Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
2013
 
2012
 
2011
 
Expected term (in years)(1)
6.5

 
6.5

 
6.5

 
Risk-free interest rate(2)
1.4

%
1.2 – 1.6

%
1.7 – 3.2

%
Expected volatility(3)
25.6

%
27.0 – 30.5

%
31.2 – 44.9

%
Dividend yield(4)
—

 
—

 
—

 
Weighted average grant-date fair value (per option)
$
5.31

 
$
5.18

 
$
5.49

 
___________
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3)
Volatility calculated using the implied volatility of our exchange traded stock options.
(4)
We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future
Schedule of Restricted Stock and Restricted Stock Unit Activity 
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended December 31, 2013, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2012
4,134,037

 
$
14.33

Granted
1,790,448

 
$
18.47

Forfeited
182,438

 
$
16.17

Vested
1,310,206

 
$
12.57

Nonvested — December 31, 2013
4,431,841

 
$
16.45

Capital Structure (Tables)
Schedule of Common Stock Activity
The table below summarizes our common stock activity for the years ended December 31, 2013, 2012 and 2011.
 
Shares
Issued
 
Shares
Held in
Treasury
 
Shares
Held in
Reserve
 
Total
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

Shares issued under Calpine Equity Incentive Plans
5,345,956

 
(2,323,828
)
 
—

 
3,022,128

Share repurchase program
—

 
(31,032,110
)
 
—

 
(31,032,110
)
Balance, December 31, 2013
497,841,056

 
(68,802,068
)
 
—

 
429,038,988

Commitments and Contingencies (Tables)
Schedule Of Future Minimum Payments For Commodities [Table Text Block] 
At December 31, 2013, we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions):
2014
$
385

2015
290

2016
238

2017
235

2018
224

Thereafter
815

Total
$
2,187

Schedule of Future Minimum Rental Payments for Power Plant and Land and Other Operating Leases 
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 at December 31, 2013, are as follows (in millions):
2014
$
632

2015
641

2016
582

2017
546

2018
517

Thereafter
2,577

Total
$
5,495

Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
 
Initial
Year
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
Land and other operating leases
various
 
$
15

 
$
15

 
$
15

 
$
15

 
$
15

 
$
215

 
$
290

Power plant operating leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Greenleaf
1998
 
$
7

 
$
4

 
$
—

 
$
—

 
$
—

 
$
—

 
$
11

KIAC
2000
 
24

 
23

 
22

 
22

 
22

 
30

 
143

Total power plant leases
 
 
$
31

 
$
27

 
$
22

 
$
22

 
$
22

 
$
30

 
$
154

Total leases
 
 
$
46

 
$
42

 
$
37

 
$
37

 
$
37

 
$
245

 
$
444

Schedule of Future Minimum Lease Payments for Office and Equipment Leases 
Future minimum lease payments under these leases are as follows (in millions):
2014
$
11

2015
10

2016
10

2017
11

2018
10

Thereafter
28

Total
$
80

Schedule of Guarantor Obligations 
At December 31, 2013, 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
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
Guarantee of subsidiary debt(1)
 
$
36

 
$
37

 
$
36

 
$
26

 
$
31

 
$
178

 
$
344

Standby letters of credit(2)(4)
 
562

 
11

 
—

 
20

 
—

 
37

 
630

Surety bonds(3)(4)(5)
 
—

 
—

 
—

 
—

 
—

 
27

 
27

 Guarantee of subsidiary operating lease payments(4)
 
7

 
4

 
—

 
—

 
—

 
—

 
11

Total
 
$
605

 
$
52

 
$
36

 
$
46

 
$
31

 
$
242

 
$
1,012

____________
(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, 2013, $4 million of cash collateral is outstanding related to these bonds.
Segment and Significant Customer Information (Tables)
Schedule of Financial Data for Segments
The tables below show our financial data for our segments for the periods indicated (in millions).
 
Year Ended December 31, 2013
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,937

 
$
2,347

 
$
1,356

 
$
661

 
$
—

 
$
6,301

Intersegment revenues
5

 
(4
)
 
33

 
189

 
(223
)
 
—

Total operating revenues
$
1,942

 
$
2,343

 
$
1,389

 
$
850

 
$
(223
)
 
$
6,301

Commodity Margin
$
1,020

 
$
632

 
$
712

 
$
204

 
$
—

 
$
2,568

Add: Unrealized mark-to-market commodity activity, net and other(1)
(50
)
 
51

 
5

 
22

 
(31
)
 
(3
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
365

 
269

 
172

 
120

 
(31
)
 
895

Depreciation and amortization expense
243

 
165

 
130

 
73

 
(2
)
 
609

Sales, general and other administrative expense
37

 
56

 
21

 
21

 
1

 
136

Other operating expenses
45

 
3

 
29

 
4

 
—

 
81

(Income) from unconsolidated investments in power plants
—

 
—

 
(30
)
 
—

 
—

 
(30
)
Income from operations
280

 
190

 
395

 
8

 
1

 
874

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
690

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
164

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
20


 
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(2)(3)
$
994

 
$
570

 
$
729

 
$
245

 
$
—

 
$
2,538

Add: Unrealized mark-to-market commodity activity, net and other(1)
(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
 
 
 
 
 
 
 
 
 
 
$
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(2)(3)
$
1,061

 
$
469

 
$
704

 
$
240

 
$
—

 
$
2,474

Add: Unrealized mark-to-market commodity activity, net and other(1)
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
 
 
 
 
 
 
 
 
 
 
$
(211
)
__________
(1)
Includes $6 million, $1 million and $12 million of lease levelization and $14 million, $14 million and $8 million of amortization expense for the years ended December 31, 2013, 2012 and 2011, respectively.
(2)
Our North segment includes Commodity Margin of $73 million and $70 million for the years ended December 31, 2012 and 2011, respectively, related to Riverside Energy Center, LLC, which was sold in December 2012.
(3)
Our Southeast segment includes Commodity Margin of $52 million and $51 million for the years ended December 31, 2012 and 2011, respectively, related to Broad River, which was sold in December 2012.
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)
2013
 
 
 
 
 
 
 
Operating revenues
$
1,438

 
$
2,050

 
$
1,572

 
$
1,241

Income from operations
$
151

 
$
597

 
$
122

 
$
4

Net income (loss) attributable to Calpine
$
(97
)
 
$
306

 
$
(70
)
 
$
(125
)
Net income (loss) per common share attributable to Calpine — Basic
$
(0.23
)
 
$
0.70

 
$
(0.16
)
 
$
(0.28
)
Net income (loss) per common share attributable to Calpine — Diluted
$
(0.23
)
 
$
0.70

 
$
(0.16
)
 
$
(0.28
)
 
 
 
 
 
 
 
 
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
)
Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2013
Freestone Energy Center [Member]
Dec. 31, 2013
Hidalgo Energy Center [Member]
Dec. 31, 2013
Debt Service
Dec. 31, 2012
Debt Service
Dec. 31, 2013
Rent Reserve [Member]
Dec. 31, 2012
Rent Reserve [Member]
Dec. 31, 2013
Construction Major Maintenance
Dec. 31, 2012
Construction Major Maintenance
Dec. 31, 2013
Security Project Insurance
Dec. 31, 2012
Security Project Insurance
Dec. 31, 2013
Other
Dec. 31, 2012
Other
Dec. 31, 2013
Greenfield [Member]
Dec. 31, 2013
Whitby [Member]
Dec. 31, 2012
Comprehensive Income [Member]
Dec. 31, 2011
Comprehensive Income [Member]
Dec. 31, 2012
Cash Flow Statement [Member]
Dec. 31, 2011
Cash Flow Statement [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior Period Reclassification Adjustment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ (6)
$ (14)
$ 5 
$ 0 
Held-to-maturity Securities, Restricted
24 
25 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
203 
193 
 
 
11 1
11 1
3 
0 
35 
32 
151 
101 
3 
49 
 
 
 
 
 
 
Non-current
69 
60 
 
 
41 1
41 1
0 
0 
20 
14 
6 
3 
2 
2 
 
 
 
 
 
 
Total
272 
253 
 
 
52 1
52 1
3 
0 
55 
46 
157 
104 
5 
51 
 
 
 
 
 
 
Prior Period Adjustment [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership percentage in equity method investment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50.00% 
50.00% 
 
 
 
 
Cash and cash equivalents subject to project finance facilities and lease agreements
292 
131 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Inventory
364 
301 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, salvage value (as a percent)
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment, salvage value of rotables (as a percent)
0.15% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset retirement obligations
44 
38 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jointly Owned Plants [Abstract]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jointly Owned Utility Plant, Proportionate Ownership Share
 
 
75.00% 
78.50% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service
 
 
393 
255 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation
 
 
(135)
(93)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress
 
 
$ 0 
$ 0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of Significant Accounting Policies Contractual Future Minimum Lease Receipt Table (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]
 
Operating Leases, Future Minimum Payments Receivable, Current
$ 632 
Operating Leases, Future Minimum Payments Receivable, in Two Years
641 
Operating Leases, Future Minimum Payments Receivable, in Three Years
582 
Operating Leases, Future Minimum Payments Receivable, in Four Years
546 
Operating Leases, Future Minimum Payments Receivable, in Five Years
517 
Operating Leases, Future Minimum Payments Receivable, Thereafter
2,577 
Operating Leases, Future Minimum Payments Receivable
$ 5,495 
Acquisitions, Divestitures and Discontinued Operations (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2013
MW
Dec. 31, 2013
MW
Dec. 31, 2012
MW
Dec. 31, 2011
Dec. 31, 2013
Guadalupe Energy Center [Member]
MW
Dec. 31, 2013
Guadalupe Expansion Capacity [Member]
MW
Dec. 31, 2012
Bosque Energy Center [Member]
MW
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]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
Power generation capacity
9,027 
9,027 
8,255 
 
1,050 
400 
800 
603 
847 
 
Proceeds from Sale of Productive Assets
 
 
 
 
 
 
 
$ 402 
$ 423 
 
Number of 525 MW generation blocks to be acquired in the Guadalupe acquisition
2 
 
 
 
 
 
 
 
 
 
Business Acquisition, Purchase Price Allocation, Assets Acquired
 
 
 
 
625 
15 
432 
 
 
 
Block one power generation capacity
 
 
 
 
 
 
250 
 
 
 
Block two power generation capacity
 
 
 
 
 
 
550 
 
 
 
Gain (Loss) on Disposition of Assets
 
$ 0 
$ 222 
$ 0 
 
 
 
$ 7 
$ 215 
 
Ownership percentage before divestiture of business
 
 
 
 
 
 
 
 
 
100.00% 
Property, Plant and Equipment, Net (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Property, Plant and Equipment [Line Items]
 
 
 
Buildings, machinery and equipment
$ 15,838 
$ 14,774 
 
Geothermal properties
1,265 
1,243 
 
Other
164 
142 
 
Property, Plant and Equipment, Gross
17,267 
16,159 
 
Less: Accumulated depreciation
4,897 
4,390 
 
Property, Plant and Equipment, Gross, Less Accumulated Depreciation
12,370 
11,769 
 
Land
103 
98 
 
Construction in progress
522 1
1,138 1
 
Property, plant and equipment, net
12,995 
13,005 
 
Interest Costs, Capitalized During Period
$ 38 
$ 38 
$ 24 
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, 2013
Dec. 31, 2012
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
$ 93 
$ 81 
Greenfield [Member]
 
 
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
76 
69 
Equity Method Investment, Ownership Percentage
50.00% 
 
Whitby [Member]
 
 
Equity Method Investments Included on Balance Sheet [Abstract]
 
 
Equity Method Investments
$ 17 
$ 12 
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, 2013
Dec. 31, 2012
Dec. 31, 2011
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) from unconsolidated investments in power plants
$ (30)
$ (28)
$ (21)
Return on investment in unconsolidated subsidiaries
27 
29 
6 
Greenfield [Member]
 
 
 
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) from unconsolidated investments in power plants
(16)
(17)
(12)
Return on investment in unconsolidated subsidiaries
18 
22 
2 
Whitby [Member]
 
 
 
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
 
 
 
(Income) from unconsolidated investments in power plants
(14)
(11)
(9)
Return on investment in unconsolidated subsidiaries
$ 9 
$ 7 
$ 4 
Variable Interest Entities and Unconsolidated Investments (Equity Method Investment Summarized Financial Information) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Equity Method Investment, Summarized Financial Information, Assets [Abstract]
 
 
 
Equity Method Investment Summarized Financial Information Cash and Cash Equivalents
$ 57 
$ 64 
 
Equity Method Investment, Summarized Financial Information, Current Assets
25 
30 
 
Equity Method Investment, Summarized Financial Information, Property, Plant and Equipment, net
588 
648 
 
Equity Method Investment, Summarized Financial Information, Noncurrent Assets
2 
4 
 
Equity Method Investment, Summarized Financial Information, Assets
672 
746 
 
Equity Method Investment, Summarized Financial Information, Liabilities [Abstract]
 
 
 
Equity Method Investment, Summarized Financial Information, Current Maturities of Long-term Debt
23 
25 
 
Equity Method Investment, Summarized Financial Information, Current Liabilities
44 
36 
 
Equity Method Investment, Summarized Financial Information, Long-Term Debt
372 
423 
 
Equity Method Investment, Summarized Financial Information, Long-term Derivative Liabilities
35 
84 
 
Equity Method Investment, Summarized Financial Information, Liabilities
474 
568 
 
Equity Method Investment Summarized Financial Information, Equity [Abstract]
 
 
 
Equity Method Investment Summarized Financial Information, Equity
198 
178 
 
Equity Method Investment, Summarized Financial Information, Liabilities and Equity
672 
746 
 
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) [Abstract]
 
 
 
Equity Method Investment, Summarized Financial Information, Revenue
207 
247 
277 
Equity Method Investment, Summarized Financial Information, Cost of Sales
128 
171 
208 
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)
79 
76 
69 
Equity Method Investment Summarized Financial Information Interest (Income) Expense
24 
27 
30 
Equity Method Investment Summarized Financial Information Other (Income) Expense Net
(3)
(2)
2 
Equity Method Investment, Summarized Financial Information, Net Income (Loss)
$ 58 
$ 51 
$ 37 
Variable Interest Entities and Unconsolidated Investments (VIE Textuals) (Details) (USD $)
12 Months Ended
Dec. 31, 2013
MW
Dec. 31, 2012
MW
Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
 
 
 
Power generation capacity
9,027 
8,255 
 
Variable Interest Entity, Financial or Other Support, Amount
$ 0 
$ 20,000,000 
$ 87,000,000 
Equity Method Investment, Summarized Financial Information, Debt
395,000,000 
448,000,000 
 
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt
$ 198,000,000 
$ 224,000,000 
 
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% 
 
 
Whitby [Member]
 
 
 
Schedule of Equity Method Investments [Line Items]
 
 
 
Power generation capacity
50 
 
 
Equity Method Investment, Ownership Percentage
50.00% 
 
 
Debt (Debt) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,112 
$ 10,750 
Debt, Current
204 
115 
Debt, net of current portion
10,908 
10,635 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
4,989 
5,303 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,901 
1,789 
CCFC Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,191 
0 
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,828 
2,463 
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 
978 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 203 
$ 217 
Debt (Annual Debt Marturities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Long-term Debt, Fiscal Year Maturity [Abstract]
 
 
2013
$ 205 
 
2014
183 
 
2015
194 
 
2016
550 
 
2017
1,717 
 
Thereafter
8,291 
 
Total debt, gross
11,140 
 
Less: Discount
28 
 
Long-term Debt
$ 11,112 
$ 10,750 
Debt Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,112 
$ 10,750 
First Lien Notes 2017 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
7.50% 1
Long-term Debt
0 2
1,080 2
First Lien Notes 2017 [Member] |
Early Tender Amount [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
742 
 
First Lien Notes 2017 [Member] |
Remaining Tender Amount [Member] [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
338 
 
First Lien Notes 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
8.20% 1
8.20% 1
Long-term Debt
320 3
360 3
First Lien Notes 2020 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
8.20% 1
8.10% 1
Long-term Debt
875 3
983 3
First Lien Notes 2021 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
7.70% 1
7.70% 1
Long-term Debt
1,600 3
1,800 3
2022 First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
6.20% 1
0.00% 1
Long-term Debt
744 2
0 2
First Lien Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
8.00% 1
8.00% 1
Long-term Debt
960 3
1,080 3
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
4,989 
5,303 
2024 First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Interest Rate, Effective Percentage
5.90% 1
0.00% 1
Long-term Debt
$ 490 3
$ 0 3
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed
10.00% 
 
Debt Instrument, Redemption Price, Percentage
103.00% 
 
[2] On October 17, 2013, we launched a tender offer to repay our 2017 First Lien Notes with the proceeds from our 2020 First Lien Term Loan and 2022 First Lien Notes which are described in further detail below. On October 31, 2013, following the early tender and consent date of the tender offer, we purchased approximately $742 million in aggregate principal amount of our 2017 First Lien Notes and issued a redemption notice to the remaining holders of our 2017 First Lien Notes that did not tender their notes in the tender offer. The tender offer expired on November 29, 2013 and we purchased the remaining $338 million in aggregate principal amount of our 2017 First Lien Notes tendered prior to the expiration of the tender offer, and redeemed any remaining 2017 First Lien Notes on December 2, 2013.
Debt Debt (First Lien Term Loans) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,112 
$ 10,750 
First Lien Term Loans 2018 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,614 
1,630 
Debt Instrument, Interest Rate, Effective Percentage
4.30% 1
4.70% 1
First Lien Term Loan 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
824 
833 
Debt Instrument, Interest Rate, Effective Percentage
4.50% 1
4.70% 1
2020 First Lien Term Loan [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
390 
0 
Debt Instrument, Interest Rate, Effective Percentage
4.30% 1
0.00% 1
First Lien Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 2,828 
$ 2,463 
Debt (Project Financing, Notes Payable and Others) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,112 
$ 10,750 
Steamboat [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
418 
428 
Debt Instrument, Interest Rate, Effective Percentage
6.80% 1
6.80% 1
OMEC [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
335 
345 
Debt Instrument, Interest Rate, Effective Percentage
6.90% 1
6.80% 1
Russell City Project [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
593 
507 
Debt Instrument, Interest Rate, Effective Percentage
4.90% 1
3.60% 1
Pasadena [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
135 2
160 2
Debt Instrument, Interest Rate, Effective Percentage
8.90% 1 2
8.90% 1 2
Bethpage [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
88 3
93 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
305 
209 
Debt Instrument, Interest Rate, Effective Percentage
3.40% 1
3.50% 1
Gilroy note payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
15 
33 
Debt Instrument, Interest Rate, Effective Percentage
11.20% 1
10.80% 1
Other Debt Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
12 
14 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
0.00% 1
Project Financing Total [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 1,901 
$ 1,789 
Debt (Capital Lease Obligations) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Minimum Lease Payments, Sale Leaseback Transactions, Fiscal Year Maturity [Abstract]
 
Minimum Lease Payments, Sale Leaseback Transactions, within One Year
$ 25 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
17 1
Minimum Lease Payments, Sale Leaseback Transactions, within Five Years
21 1
Minimum Lease Payments, Sale Leaseback Transactions, Thereafter
106 1
Minimum Lease Payments, Sale Leaseback Transactions
219 1
Interest Portion of Minimum Lease Payments, Sale Leaseback Transactions
84 1
Present Value of Future Minimum Lease Payments, Sale Leaseback Transactions
135 1
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
 
Capital Leases, Future Minimum Payments Due, Current
51 
Capital Leases, Future Minimum Payments Due in Two Years
38 
Capital Leases, Future Minimum Payments Due in Three Years
40 
Capital Leases, Future Minimum Payments Due in Four Years
38 
Capital Leases, Future Minimum Payments Due in Five Years
37 
Capital Leases, Future Minimum Payments Due Thereafter
125 
Capital Leases, Future Minimum Payments Due
329 
Capital Leases, Future Minimum Payments, Interest Included in Payments
126 
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments
203 
Total Leases Future Minimum Payments [Abstract]
 
Total Leases, Future Minimum Payments Due, Current
76 
Total Leases, Future Minimum Payments Due in Two Years
63 
Total Leases, Future Minimum Payments Due in Three Years
65 
Total Leases, Future Minimum Payments Due in Four Years
55 
Total Leases, Future Minimum Payments Due in Five Years
58 
Total Leases, Future Minimum Payments Due Thereafter
231 
Total Leases, Future Minimum Payments Due
548 
Total Leases, Future Minimum Payments, Interest Included in Payments
210 
Total Leases, Future Minimum Payments, Present Value of Net Minimum Payments
$ 338 
Debt (Corporate Revolving Facility and other Letters of Credit Facilities) (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2013
Corporate Revolving Facility [Member]
Dec. 31, 2012
Corporate Revolving Facility [Member]
Dec. 31, 2013
CDH [Member]
Dec. 31, 2012
CDH [Member]
Dec. 31, 2013
Various Project Financing Facilities [Member]
Dec. 31, 2012
Various Project Financing Facilities [Member]
Jun. 30, 2013
Corporate Revolving Facility Amendment No. 1 [Member]
Jun. 30, 2013
Corporate Revolving Facility [Member]
Line of Credit Facility [Line Items]
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
 
 
 
 
 
 
 
 
2.25% 
3.25% 
Line of Credit Facility, Fair Value of Amount Outstanding
$ 630 
$ 626 
$ 242 
$ 243 
$ 218 
$ 253 
$ 170 
$ 130 
 
 
Term loan interest rate spread option Prime Rate
 
 
 
 
 
 
 
 
1.25% 
2.25% 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
 
 
 
 
 
 
 
 
0.50% 
0.75% 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Portion at Fair Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
$ 5,317 
$ 5,863 
Notes Payable, Other Payables, Disclosure
1,772 1
1,599 1
Subsidiaries Term Loan
1,179 
0 
Loans Payable, Fair Value Disclosure
2,845 
2,489 
Subsidiaries Notes Disclosure
0 
1,075 
Debt Excluding Capital Leases
11,113 
11,026 
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
4,989 
5,303 
Notes Payable, Other Payables, Disclosure
1,766 1
1,629 1
Subsidiaries Term Loan
1,191 
0 
Loans Payable, Fair Value Disclosure
2,828 
2,463 
Subsidiaries Notes Disclosure
0 
978 
Debt Excluding Capital Leases
$ 10,774 
$ 10,373 
Debt (Textuals) (Details) (USD $)
12 Months Ended 6 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2013
First Lien Term Loans [Member]
Dec. 31, 2013
CCFC Notes [Member]
Jun. 30, 2013
Corporate Revolving Facility [Member]
Dec. 31, 2013
Corporate Revolving Facility [Member]
Dec. 31, 2013
Corporate Revolving Facility [Member]
Minimum [Member]
Dec. 31, 2013
Corporate Revolving Facility [Member]
Maximum [Member]
Dec. 31, 2013
CDHI [Member]
Dec. 31, 2013
One Month [Member]
Corporate Revolving Facility [Member]
Dec. 31, 2013
Two Months [Member]
Corporate Revolving Facility [Member]
Dec. 31, 2013
Three Months [Member]
Corporate Revolving Facility [Member]
Dec. 31, 2013
Six Months [Member]
Corporate Revolving Facility [Member]
Dec. 31, 2013
Nine Months [Member]
Corporate Revolving Facility [Member]
Dec. 31, 2013
Twelve Months [Member]
Corporate Revolving Facility [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
 
 
 
2.00% 
 
2.25% 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
 
 
 
3.00% 
 
3.25% 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of principal amount of Term Loan to be paid quarterly
 
 
 
0.25% 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
$ 1,000,000,000 
 
 
 
 
 
 
 
 
 
 
 
Gains (Losses) on Extinguishment of Debt
(144,000,000)
(30,000,000)
(94,000,000)
 
68,000,000 
 
 
 
 
 
 
 
 
 
 
 
Maximum Remaining Lease Term
35 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease Assets, Historical Cost
862,000,000 
880,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease Assets, Accumulated Depreciation
343,000,000 
312,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Applicable margin range percentage above base rate
 
 
 
 
 
 
 
1.00% 
1.25% 
 
 
 
 
 
 
 
Percentage added to Federal Funds Effective Rate to arrive at base rate
 
 
 
 
 
 
0.50% 
 
 
 
 
 
 
 
 
 
Interest periods for LIBOR rate borrowings
 
 
 
 
 
 
 
 
 
 
1 month 
2 months 
3 months 
6 months 
9 months 
12 months 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
 
 
 
 
 
 
 
2.00% 
2.25% 
 
 
 
 
 
 
 
Repayment time for drawings under letters of credit
 
 
 
 
 
 
2 days 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
 
 
 
 
 
0.75% 
 
0.25% 
0.50% 
 
 
 
 
 
 
 
Excess amount of asset sales requiring mandatory prepayments
 
 
 
 
 
 
3,000,000,000 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
$ 0 
 
 
 
 
 
 
Debt 2024 First Lien Notes (Details) (USD $)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
 
Gains (Losses) on Extinguishment of Debt
$ (144,000,000)
$ (30,000,000)
$ (94,000,000)
2024 First Lien Notes [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
490,000,000 
 
 
Debt Instrument, Interest Rate, Stated Percentage
5.875% 
 
 
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed
10.00% 
 
 
Debt Instrument, Redemption Price, Percentage
103.00% 
 
 
Deferred Finance Costs, Net
8,000,000 
 
 
Gains (Losses) on Extinguishment of Debt
$ 20,000,000 
 
 
Debt 2022 First Lien Notes (Details) (USD $)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
 
Gains (Losses) on Extinguishment of Debt
$ (144,000,000)
$ (30,000,000)
$ (94,000,000)
2022 First Lien Notes [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
750,000,000 
 
 
Debt Instrument, Interest Rate, Stated Percentage
6.00% 
 
 
Long Term Debt net of Original Issuance Disount
99.193% 
 
 
Deferred Finance Costs, Net
12,000,000 
 
 
Gains (Losses) on Extinguishment of Debt
$ 51,000,000 
 
 
Debt 2020 First Lien Term Loan (Details) (2020 First Lien Term Loan [Member], USD $)
Dec. 31, 2013
2020 First Lien Term Loan [Member]
 
Debt Instrument [Line Items]
 
Debt Instrument, Face Amount
$ 390,000,000 
Deferred Finance Costs, Net
$ 6,000,000 
Debt CCFC Notes and CCFC Term Loans (Details) (USD $)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
 
Long-term Debt
$ 11,112,000,000 
$ 10,750,000,000 
 
Gains (Losses) on Extinguishment of Debt
(144,000,000)
(30,000,000)
(94,000,000)
CCFC Term Loans and CCFC Notes, Total
1,191,000,000 
978,000,000 
 
CCFC Term Loan B-1 [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
900,000,000 
 
 
Term Loan Period
7 years 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
2.25% 
 
 
Term loan interest rate spread option Prime Rate
1.25% 
 
 
CCFC Term Loan B-2 [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
300,000,000 
 
 
Term Loan Period
8 years 6 months 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
2.50% 
 
 
Term loan interest rate spread option Prime Rate
1.50% 
 
 
CCFC Notes [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
1,000,000,000 
 
 
Gains (Losses) on Extinguishment of Debt
68,000,000 
 
 
CCFC Term Loans [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Deferred Finance Costs, Net
15,000,000 
 
 
Long-term Debt
1,191,000,000 
0 
 
Debt Instrument, Interest Rate, Effective Percentage
3.30% 1
0.00% 1
 
Debt Instrument, Redemption Price, Percentage
104.00% 
 
 
Term loan interest rate spread option Federal Funds effective rate
0.50% 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum
0.75% 
 
 
Long Term Debt net of Original Issuance Disount
99.75% 
 
 
Percentage of the principal amount of the Term Loan to be paid quarterly
0.25% 
 
 
Secured Debt [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Long-term Debt
$ 0 
$ 978,000,000 
 
Debt Instrument, Interest Rate, Effective Percentage
0.00% 1
8.90% 1
 
Assets and Liabilities with Recurring Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 1,134 1
$ 1,502 1
Margin Deposit Assets
261 2
196 2
Commodity futures contracts
434 
385 
Commodity forward contracts
107 3
48 3
Interest rate swaps
9 
4 
Total assets
1,945 
2,135 
Security Deposit Liability
5 2 4
11 2 4
Commodity futures contracts
495 
424 
Commodity forward contracts
70 3
26 3
Interest rate swaps
129 
200 
Total liabilities
699 
661 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1,134 1
1,502 1
Margin Deposit Assets
261 
196 
Commodity futures contracts
434 
385 
Commodity forward contracts
0 3
0 3
Interest rate swaps
0 
0 
Total assets
1,829 
2,083 
Security Deposit Liability
5 
11 
Commodity futures contracts
495 
424 
Commodity forward contracts
0 3
0 3
Interest rate swaps
0 
0 
Total liabilities
500 
435 
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
0 1
0 1
Margin Deposit Assets
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
75 3
24 3
Interest rate swaps
9 
4 
Total assets
84 
28 
Security Deposit Liability
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
52 3
18 3
Interest rate swaps
129 
200 
Total liabilities
181 
218 
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
0 1
0 1
Margin Deposit Assets
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
32 3
24 3
Interest rate swaps
0 
0 
Total assets
32 
24 
Security Deposit Liability
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
18 3
8 3
Interest rate swaps
0 
0 
Total liabilities
$ 18 
$ 8 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
Balance, beginning of period
$ 16 
$ 17 
$ 30 
Included in net income:
 
 
 
Included in operating revenues
5 1
8 1
5 1
Included in fuel and purchased energy expense
0 2
0 2
0 2
Included in OCI
0 
0 
2 
Purchases, issuances and settlements:
 
 
 
Purchases
6 
3 
0 
Issuances
(2)
(1)
0 
Settlements
(11)
(11)
(18)
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount
0 
0 
0 
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount
0 
0 
0 
Transfers into level 3
0 3 4
0 3 4
(2)3 4
Transfers out of level 3
0 3 5
0 3 5
0 3 5
Balance, end of period
14 
16 
17 
Change in unrealized gains relating to instruments still held at end of period
5 
8 
5 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure
889 
1,274 
 
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure
$ 245 
$ 228 
 
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Information about Level 3 Fair Value Measurements (Details) (USD $)
Dec. 31, 2013
Dec. 31, 2012
Physical Power [Member]
 
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
$ 7,000,000 
$ 11,000,000 
Power Congestion Products [Member]
 
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
7,000,000 
 
Minimum [Member] |
Physical Power [Member]
 
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
28.92 
23.75 
Minimum [Member] |
Power Congestion Products [Member]
 
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
(8.79)
 
Maximum [Member] |
Physical Power [Member]
 
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
53.15 
53.82 
Maximum [Member] |
Power Congestion Products [Member]
 
 
Quantitative Information about Level 3 fair Value Measurements [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
$ 11.53 
 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
MWh
MMBTU
Dec. 31, 2012
MWh
MMBTU
Derivative Instruments [Abstract]
 
 
Power (MWh)
(29)
(16)
Natural gas (MMBtu)
448 
66 
Interest rate swaps
$ 1,527 
$ 1,602 
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
$ 445 
$ 339 
Derivative Asset, Noncurrent
105 
98 
Total derivative assets
550 
437 
Derivative Liability, Current
451 
357 
Derivative Liability, Noncurrent
243 
293 
Derivative Liability, Fair Value, Gross Liability
694 
650 
Net derivative assets (liabilities)
(144)
(213)
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
9 
4 
Derivative Liability, Fair Value, Gross Liability
115 
184 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
541 
433 
Derivative Liability, Fair Value, Gross Liability
579 
466 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
0 
0 
Derivative Asset, Noncurrent
9 
4 
Total derivative assets
9 
4 
Derivative Liability, Current
47 
40 
Derivative Liability, Noncurrent
82 
160 
Derivative Liability, Fair Value, Gross Liability
129 
200 
Net derivative assets (liabilities)
(120)
(196)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
9 
4 
Derivative Liability, Fair Value, Gross Liability
115 
184 
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
0 
0 
Derivative Liability, Fair Value, Gross Liability
14 
16 
Commodity Option [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
445 
339 
Derivative Asset, Noncurrent
96 
94 
Total derivative assets
541 
433 
Derivative Liability, Current
404 
317 
Derivative Liability, Noncurrent
161 
133 
Derivative Liability, Fair Value, Gross Liability
565 
450 
Net derivative assets (liabilities)
(24)
(17)
Commodity Option [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
541 
433 
Derivative Liability, Fair Value, Gross Liability
$ 565 
$ 450 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gain (Loss) on Sale of Derivatives
$ 86 1
$ 230 1
$ (50)1
Unrealized Gain (Loss) on Derivatives
(12)2
72 2
30 2
Gain (Loss) on Derivative Instruments, Net, Pretax
74 
302 
(20)
Power contracts included in operating revenues
(119)
187 
(20)
Natural gas contracts included in fuel and purchased energy expense
191 
118 
138 
Interest rate swaps included in interest expense
2 
11 
7 
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
0 
(14)
(145)
Interest Rate Swap [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gain (Loss) on Sale of Derivatives
0 1
(157)1
(193)1
Unrealized Gain (Loss) on Derivatives
2 2
154 2
55 2
Commodity Option [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gain (Loss) on Sale of Derivatives
86 1
387 1
143 1
Unrealized Gain (Loss) on Derivatives
$ (14)2
$ (82)2
$ (25)2
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
$ 86 1
$ (81)1
$ (94)1
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
(51)1
20 1
25 1
Power Derivative Instruments [Member] |
Commodity Option [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
0 1 2
(97)1 2
(99)1 2
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
0 2 3
118 2 3
236 2 3
Natural Gas Derivative Instruments [Member] |
Commodity Option [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
0 1 2
59 1 2
28 1 2
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
0 2 3
(66)2 3
(73)2 3
Interest Expense [Member] |
Interest Rate Swap [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
86 1 4
(43)1 4
(23)1 4
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
(51)3 4 5
(32)3 4
(47)3 4 6
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments [Member] |
Interest Rate Swap [Member]
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
0 1
0 1
0 1
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
$ 0 3
$ 0 3
$ (91)3
Derivative Instruments (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Derivatives, Fair Value [Line Items]
 
 
 
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net
$ 0 
$ 2 
$ (2)
Derivative Instruments (Textuals) [Abstract]
 
 
 
Maximum length of time hedging using interest rate derivative instruments
10 years 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
8 
 
 
Collateral Already Posted, Aggregate Fair Value
1 
 
 
Additional Collateral, Aggregate Fair Value
0 
 
 
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net
12 
 
91 
Unrealized losses associated with interest rate swap breakage costs
3 
11 
44 
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months
43 
 
 
Losses from interest rate contracts reclassified from OCI into earnings
 
 
15 
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
0 
(14)
(145)
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Unrealized
 
14 
 
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Realized
 
142 
 
Interest Rate Swap [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net
 
 
(1)
Interest Rate Swap [Member]
 
 
 
Derivative Instruments (Textuals) [Abstract]
 
 
 
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
 
156 
 
Parent [Member]
 
 
 
Derivative Instruments (Textuals) [Abstract]
 
 
 
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax
(148)
(222)
(158)
Noncontrolling Interest [Member]
 
 
 
Derivative Instruments (Textuals) [Abstract]
 
 
 
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax
$ (11)
$ (20)
$ (14)
Derivative Instruments (Detail 5) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Derivative [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 550 
$ 437 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(480)
(396)
Derivative, Collateral, Obligation to Return Cash
14 1
7 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
56 
34 
Derivative Liability, Fair Value, Gross Liability
694 
650 
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
480 
396 
Derivative, Collateral, Right to Reclaim Cash
76 1
46 1
Derivative Liability, Fair Value, Amount Offset Against Collateral
138 
208 
Derivative, Fair Value, Net
(144)
(213)
Derivative Fair Value, Amount Not Offset Against Collateral, Net
0 
0 
Derivative, Collateral, Right to Reclaim Cash, Net
62 1
39 1
Derivative, Fair Value, Amount Offset Against Collateral, Net
(82)
(174)
Commodity Option [Member]
 
 
Derivative [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
541 
433 
Derivative Liability, Fair Value, Gross Liability
565 
450 
Derivative, Fair Value, Net
(24)
(17)
Commodity Exchange Traded Futures and Swaps Contracts [Member]
 
 
Derivative [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
434 
385 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(420)
(379)
Derivative, Collateral, Obligation to Return Cash
14 1
6 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
0 
0 
Derivative Liability, Fair Value, Gross Liability
495 
424 
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
420 
379 
Derivative, Collateral, Right to Reclaim Cash
75 1
45 1
Derivative Liability, Fair Value, Amount Offset Against Collateral
0 
0 
Commodity Forward Contract [Member]
 
 
Derivative [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
107 
48 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(60)
(17)
Derivative, Collateral, Obligation to Return Cash
0 1
1 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
47 
30 
Derivative Liability, Fair Value, Gross Liability
70 
26 
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
60 
17 
Derivative, Collateral, Right to Reclaim Cash
1 1
1 1
Derivative Liability, Fair Value, Amount Offset Against Collateral
9 
8 
Interest Rate Swap [Member]
 
 
Derivative [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
9 
4 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
0 
0 
Derivative, Collateral, Obligation to Return Cash
0 1
0 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
9 
4 
Derivative Liability, Fair Value, Gross Liability
129 
200 
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
0 
0 
Derivative, Collateral, Right to Reclaim Cash
0 1
0 1
Derivative Liability, Fair Value, Amount Offset Against Collateral
129 
200 
Derivative, Fair Value, Net
$ (120)
$ (196)
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Use of Collateral [Abstract]
 
 
Margin Deposit Assets
$ 261 1
$ 196 1
Natural gas and power prepayments
28 
35 
Total margin deposits and natural gas and power prepayments with our counterparties
289 2
231 2
Letters of credit issued
488 
484 
First priority liens under power and natural gas agreements
31 
14 
First priority liens under interest rate swap agreements
132 
206 
Total letters of credit and first priority liens with our counterparties
651 
704 
Security Deposit Liability
5 1 3
11 1 3
Letters of credit posted with us by our counterparties
2 
1 
Total margin deposits and letters of credit posted with us by our counterparties
7 
12 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
17 
20 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
$ 272 
$ 211 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Income Tax Disclosure [Abstract]
 
 
 
U.S.
$ (13)
$ 194 
$ (232)
International
29 
24 
20 
Total
$ 16 
$ 218 
$ (212)
Income Taxes (Components of Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Income Tax Disclosure [Abstract]
 
 
 
Federal
$ (2)
$ (12)
$ (16)
State
(9)
16 
12 
Foreign
(1)
14 
3 
Total current
(12)
18 
(1)
Federal
1 
11 
(33)
State
4 
(5)
9 
Foreign
9 
(5)
3 
Total deferred
14 
1 
(21)
Total income tax expense (benefit)
$ 2 
$ 19 
$ (22)
Income Taxes (Effective Income Tax Expense (Benefit) Rate) (Details)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Income Tax [Line Items]
 
 
 
Federal statutory tax expense (benefit) rate
35.00% 
35.00% 
(35.00%)
State tax expense (benefit), net of federal benefit
(69.80%)
3.20% 
6.50% 
Depletion in excess of basis
(14.70%)
(0.20%)
0.00% 
Effective Income Tax Rate Reconciliation, Tax Settlements, Domestic
0.00% 
(4.70%)
0.00% 
Valuation allowances
89.80% 
(30.30%)
57.10% 
Effective Income Tax Rate Reconciliation Change In Deferred Tax Assets Valuation Allowance Due To Reconsolidation
0.00% 
0.00% 
(36.00%)
Effective Income Tax Rate Reconciliation Change in Deferred Tax Assets, Valuation Allowance Due to Foreign Taxes
(19.80%)
(8.20%)
0.00% 
Foreign taxes
(10.80%)
3.70% 
(0.90%)
Intraperiod allocation
4.50% 
4.60% 
19.90% 
Bankruptcy settlement
0.00% 
0.00% 
(15.70%)
Change in unrecognized tax benefits
(30.10%)
5.10% 
(6.60%)
Effective Income Tax Rate Reconciliation Nondeductible Expense Disallowed Compensation
11.70% 
0.40% 
0.30% 
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Percent
8.60% 
0.20% 
0.10% 
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Percent
3.30% 
0.30% 
0.40% 
Permanent differences and other items
4.80% 
(0.40%)
(0.50%)
Effective income tax expense (benefit) rate
12.50% 
8.70% 
(10.40%)
Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Income Tax Disclosure [Abstract]
 
 
NOL and credit carryforwards
$ 3,120 
$ 3,073 
Taxes related to risk management activities and derivatives
60 
90 
Reorganization items and impairments
262 
315 
Foreign capital losses
18 
25 
Other differences
104 
60 
Deferred tax assets before valuation allowance
3,564 
3,563 
Valuation allowance
(2,246)
(2,222)
Total deferred tax assets
1,318 
1,341 
Deferred tax liabilities: property, plant and equipment
(1,310)
(1,316)
Net deferred tax asset (liability)
8 
25 
Less: Current portion deferred tax asset (liability)
12 
(3)
Less: Non-current deferred tax asset
7 
28 
Deferred income tax liability, net of current
$ (11)
$ 0 
Income Taxes (Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Continuing Operations [Member]
 
 
 
Income Tax [Line Items]
 
 
 
Deferred income tax liability, net of current
$ 1 
$ 9 
$ 42 
Other Comprehensive Income (Loss) [Member]
 
 
 
Income Tax [Line Items]
 
 
 
Deferred income tax liability, net of current
$ (1)
$ (9)
$ (45)
Income Taxes (Income Tax Contingencies) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Income Tax Disclosure [Abstract]
 
 
 
Balance, beginning of period
$ (92)
$ (74)
$ (88)
Increases related to prior year tax positions
(7)
(19)
0 
Decreases related to prior year tax positions
8 
1 
1 
Settlements
10 
0 
0 
Decrease related to lapse of statute of limitations
13 
0 
13 
Balance, end of period
$ (68)
$ (92)
$ (74)
Income Taxes (Textuals) (Details) (USD $)
3 Months Ended 12 Months Ended
Mar. 31, 2011
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Intraperiod income tax [Line Items]
 
 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, Domestic
 
$ 7,500,000,000 
 
 
 
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
 
68,000,000 
92,000,000 
74,000,000 
88,000,000 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
 
19,000,000 
 
 
 
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward
 
49,000,000 
 
 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
 
13,000,000 
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 
 
 
Valuation allowance
 
2,246,000,000 
2,222,000,000 
 
 
Valuation Allowance, Deferred Tax Asset, Change in Amount
 
24,000,000 
(114,000,000)
(50,000,000)
 
Miscellaneous increase in state, Deferred Tax Assets
 
18,000,000 
 
 
 
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
 
4,100,000,000 
 
 
 
Deferred Tax Assets, Operating Loss Carryforwards, Foreign
 
900,000,000 
 
 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense
 
(11,000,000)
4,000,000 
1,000,000 
 
Federal [Domain]
 
 
 
 
 
Income Tax Disclosure (Textuals) [Abstract]
 
 
 
 
 
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost
 
25,000,000 
16,000,000 
 
 
State and Local Jurisdiction [Member]
 
 
 
 
 
Income Tax Disclosure (Textuals) [Abstract]
 
 
 
 
 
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost
 
$ 9,000,000 
$ 7,000,000 
 
 
Earnings (Loss) per Share (Details)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Diluted weighted average shares calculation:
 
 
 
Weighted average shares outstanding (basic)
440,666 
467,752 
485,381 
Share-based awards
4,107 
3,591 
0 
Weighted average shares outstanding (in shares)
444,773 
471,343 
485,381 
Items excluded from diluted earnings (loss) per common share
 
 
 
Share-based awards
5,062 
10,302 
15,260 
Stock-Based Compensation (Details) (USD $)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
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
$ 22,000,000 
$ 1,000,000 
$ 0 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
 
 
 
Options Outstanding, Beginning balance, Number
17,862,501 
 
 
Options Outstanding, Beginning balance, Weighted Average Exercise Price
$ 17.30 
 
 
Options Ouststanding, Beginning balance, Weighted Average Remaining Term (in years)
3 years 1 month 6 days 
4 years 0 months 0 days 
 
Options Outstanding, Beginning balance, Aggregate Intrinsic Value (in $ millions)
42,000,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross
11,299 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price
$ 18.34 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period
3,724,411 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price
$ 13.70 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period
0 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price
$ 0.00 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period
35,100 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price
$ 17.69 
 
 
Options Outstanding, Ending balance, Number
14,114,289 
17,862,501 
 
Options Outstanding, Ending balance, Weighted Average Exercise Price
$ 18.25 
$ 17.30 
 
Options Ouststanding, Ending balance, Weighted Average Remaining Term (in years)
3 years 1 month 6 days 
4 years 0 months 0 days 
 
Options Outstanding, Ending balance, Aggregate Intrinsic Value (in $ millions)
36,000,000 
42,000,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number
12,475,493 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price
$ 18.70 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term
2 years 6 months 3 days 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value
29,000,000 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number
14,038,217 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price
$ 18.27 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term
3 years 1 month 6 days 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value
36,000,000 
 
 
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, Risk Free Interest Rate
1.40% 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
25.60% 
 
 
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
$ 5.31 
$ 5.18 
$ 5.49 
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
40,533,000 
 
 
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
1 
 
 
Vesting term of option grants with three year cliff vesting
3 years 
 
 
Stock-based compensation expense
34,000,000 
25,000,000 
24,000,000 
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options
20,000,000 
5,000,000 
0 
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards
2,000,000 
 
 
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, Risk Free Interest Rate
 
1.20% 
1.70% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
 
27.00% 
31.20% 
Maximum [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
 
1.60% 
3.20% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
 
30.50% 
44.90% 
Employee Stock Option [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized
1,000,000 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition
0 years 8 months 13 days 
 
 
Restricted Stock [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
25,000,000 
20,000,000 
7,000,000 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized
26,000,000 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition
1 year 1 month 9 days 
 
 
Restricted Stock and Stock Unit Activity [Abstract]
 
 
 
Nonvested Restricted Stock, Beginning balance, Number
4,134,037 
 
 
Nonvested Restricted Stock, Beginning balance, Weighted Average Grant Date Fair Value
$ 14.33 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
1,790,448 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 18.47 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
182,438 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period, Weighted Average Grant Date Fair Value
$ 16.17 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
1,310,206 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 12.57 
 
 
Nonvested Restricted Stock, Ending balance, Number
4,431,841 
4,134,037 
 
Nonvested Restricted Stock, Ending balance, Weighted Average Grant Date Fair Value
$ 16.45 
$ 14.33 
 
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, Compensation Cost Not yet Recognized
$ 0 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition
0 years 4 months 11 days 
 
 
Performance Shares [Member]
 
 
 
Restricted Stock and Stock Unit Activity [Abstract]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
449,798 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 21.25 
 
 
Defined Contribution and Defined Benefit Plans (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Defined Contribution and Defined Benefit Plans [Abstract]
 
 
 
Defined Contribution Plan, Cost Recognized
$ 11 
$ 12 
$ 10 
Employer Matching Contribution Percentage
100.00% 
 
 
Deferral Election Percentage For Employer Matching Contribution
5.00% 
 
 
Employee Deferral Limit Percentage
75.00% 
 
 
Defined Benefit Plan, Assets for Plan Benefits
14 
12 
 
Pension and Other Postretirement Defined Benefit Plans, Liabilities
20 
21 
 
Defined Benefit Plan, Amounts Recognized in Balance Sheet
6 
9 
 
Defined Benefit Plan, Net Periodic Benefit Cost
2 
1 
1 
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax
1 
5 
 
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year
1 
2 
 
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year
2 
 
 
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter
$ 1 
 
 
Capital Structure (Details) (USD $)
3 Months Ended 12 Months Ended
Dec. 31, 2013
Sep. 30, 2013
Mar. 31, 2013
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
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)
(1,400,000,000)
 
Common Stock, issued shares (in shares)
(497,841,056)
 
 
(497,841,056)
(492,495,100)
 
Common Stock, par value (in dollars per share)
$ (0.001)
 
 
$ (0.001)
$ (0.001)
 
Common Stock, outstanding shares (in shares)
(429,038,988)
 
 
(429,038,988)
(457,048,970)
 
Treasury Stock, Shares (in shares)
68,802,068 
 
 
68,802,068 
35,446,130 
 
Treasury Stock, Value
$ 1,230,000,000 
 
 
$ 1,230,000,000 
$ 594,000,000 
 
Treasury Stock, Value, Acquired, Cost Method
239,000,000 
 
 
636,000,000 
469,000,000 
120,000,000 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
Total common shares outstanding, beginning balance
 
 
(457,048,970)
(457,048,970)
(481,743,738)
(488,693,630)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
0 
Shares issued under Calpine Equity Incentive Plans
 
 
 
3,022,128 
1,741,909.000000 
1,187,181 
Share repurchase program
 
 
 
(31,032,110.00000)
(26,436,677.000000)
(8,137,073)
Total common shares outstanding, ending balance
(429,038,988)
 
 
(429,038,988)
(457,048,970)
(481,743,738)
Stock Repurchase Program, Authorized Amount
 
100,000,000 
400,000,000 
 
600,000,000 
 
Shares Issued [Member]
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
Total common shares outstanding, beginning balance
 
 
(492,495,100)
(492,495,100)
(490,468,815)
(444,883,356)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
44,258,432 
Shares issued under Calpine Equity Incentive Plans
 
 
 
5,345,956 
2,026,285 
1,327,027 
Share repurchase program
 
 
 
0 
0 
0 
Total common shares outstanding, ending balance
(497,841,056)
 
 
(497,841,056)
(492,495,100)
(490,468,815)
Shares Held inTreasury [Member]
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
Total common shares outstanding, beginning balance
 
 
(35,446,130)
(35,446,130)
(8,725,077)
(448,158)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
0 
Shares issued under Calpine Equity Incentive Plans
 
 
 
2,323,828 
284,376 
139,846 
Share repurchase program
 
 
 
(31,032,110)
(26,436,677)
(8,137,073)
Total common shares outstanding, ending balance
(68,802,068)
 
 
(68,802,068)
(35,446,130)
(8,725,077)
Shares Held in Reserve [Member]
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
Total common shares outstanding, beginning balance
 
 
0 
0 
0 
(44,258,432)
Resolution of claims/inter-creditor disputes
 
 
 
 
 
44,258,432 
Shares issued under Calpine Equity Incentive Plans
 
 
 
0 
0 
0 
Share repurchase program
 
 
 
0 
0 
0 
Total common shares outstanding, ending balance
0 
 
 
0 
0 
0 
Unfinished Program [Member]
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
Share repurchase program
 
 
 
(12,459,919)
 
 
Treasury Stock Acquired, Average Cost Per Share
 
 
 
$ 19.15 
 
 
Stock Repurchase Program, Cumulative Authorized Amount
 
 
 
1,000,000,000 
 
 
Finished Program [Member]
 
 
 
 
 
 
Common Stock Activity [Roll Forward]
 
 
 
 
 
 
Share repurchase program
 
 
 
(60,139,816)
 
 
Treasury Stock Acquired, Average Cost Per Share
 
 
 
$ 18.29 
 
 
Stock Repurchase Program, Cumulative Authorized Amount
 
 
 
$ 1,100,000,000 
 
 
Commitments and Contingencies (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Commitments and Contingencies [Line Items]
 
 
 
Guarantor Obligations, Current Carrying Value
$ 4 
 
 
Outstanding claims related to guarantees
0 
 
 
Royalty Expense
27 
22 
22 
LTSA [Member]
 
 
 
Unrecorded Unconditional Purchase Obligation
 
 
 
Unrecorded Unconditional Purchase Obligation
134 
 
 
Term of Unrecorded Unconditional Purchase Obligation Lower Limit
P1Y 
 
 
Term of Unrecorded Unconditional Purchase Obligation Upper Limit
P12Y 
 
 
Electric Generation Equipment [Member]
 
 
 
Commitments and Contingencies [Line Items]
 
 
 
Operating Leases, Rent Expense, Net
47 
51 
53 
Office Equipment [Member]
 
 
 
Commitments and Contingencies [Line Items]
 
 
 
Operating Leases, Rent Expense, Net
$ 12 
$ 12 
$ 13 
Commitments and Contingencies (Schedules of Future Minimum Rental Payments) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Land and Other Operating Leases [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
$ 290 
 
 
Operating Leases, Future Minimum Payments Due, Current
15 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
15 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
15 
 
 
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
215 
 
 
Greenleaf [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
11 
 
 
KIAC [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
143 
 
 
Operating Leases, Future Minimum Payments Due, Current
24 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
23 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
22 
 
 
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
30 
 
 
Total Power Plant Leases [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
154 
 
 
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
22 
 
 
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
30 
 
 
Operating Leases, Rent Expense, Net
47 
51 
53 
Operting Lease Assets Total [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
444 
 
 
Operating Leases, Future Minimum Payments Due, Current
46 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
42 
 
 
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
245 
 
 
Office Equipment [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
80 
 
 
Operating Leases, Future Minimum Payments Due, Current
11 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
10 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
10 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
11 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
10 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
28 
 
 
Operating Leases, Rent Expense, Net
12 
12 
13 
Greenleaf [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Guarantee Obligations Balance On First Anniversary
7 1
 
 
Guarantee Obligations Balance On Second Anniversary
4 1
 
 
Guarantee Obligations Balance On Third Anniversary
0 1
 
 
Guarantee Obligations Balance On Fourth Anniversary
0 1
 
 
Guarantee Obligations Balance On Fifth Anniversary
0 1
 
 
Guarantee Obligations Due After Five Years
0 1
 
 
Natural Gas [Member]
 
 
 
Operating Leased Assets [Line Items]
 
 
 
Operating Leases, Future Minimum Payments Due
2,187 
 
 
Operating Leases, Future Minimum Payments Due, Current
385 
 
 
Operating Leases, Future Minimum Payments, Due in Two Years
290 
 
 
Operating Leases, Future Minimum Payments, Due in Three Years
238 
 
 
Operating Leases, Future Minimum Payments, Due in Four Years
235 
 
 
Operating Leases, Future Minimum Payments, Due in Five Years
224 
 
 
Operating Leases, Future Minimum Payments, Due Thereafter
$ 815 
 
 
Commitments and Contingencies (Schedule of Guarantor Obligations) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2013
Loans Payable [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
$ 36 1
Guarantee Obligations Balance On Second Anniversary
37 1
Guarantee Obligations Balance On Third Anniversary
36 1
Guarantee Obligations Balance On Fourth Anniversary
26 1
Guarantee Obligations Balance On Fifth Anniversary
31 1
Guarantee Obligations Due After Five Years
178 1
Guarantor Obligations, Maximum Exposure, Undiscounted
344 1
Financial Standby Letter of Credit [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
562 2 3
Guarantee Obligations Balance On Second Anniversary
11 2 3
Guarantee Obligations Balance On Third Anniversary
0 2 3
Guarantee Obligations Balance On Fourth Anniversary
20 2 3
Guarantee Obligations Balance On Fifth Anniversary
0 2 3
Guarantee Obligations Due After Five Years
37 2 3
Guarantor Obligations, Maximum Exposure, Undiscounted
630 2 3
Surety Bonds [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
0 2 4 5
Guarantee Obligations Balance On Second Anniversary
0 2 4 5
Guarantee Obligations Balance On Third Anniversary
0 2 4 5
Guarantee Obligations Balance On Fourth Anniversary
0 2 4 5
Guarantee Obligations Balance On Fifth Anniversary
0 2 4 5
Guarantee Obligations Due After Five Years
27 2 4 5
Guarantor Obligations, Maximum Exposure, Undiscounted
27 2 4 5
Greenleaf [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
7 2
Guarantee Obligations Balance On Second Anniversary
4 2
Guarantee Obligations Balance On Third Anniversary
0 2
Guarantee Obligations Balance On Fourth Anniversary
0 2
Guarantee Obligations Balance On Fifth Anniversary
0 2
Guarantee Obligations Due After Five Years
0 2
Guarantor Obligations, Maximum Exposure, Undiscounted
11 2
Gurantee Obligations Total [Member]
 
Guarantor Obligations [Line Items]
 
Guarantee Obligations Balance On First Anniversary
605 
Guarantee Obligations Balance On Second Anniversary
52 
Guarantee Obligations Balance On Third Anniversary
36 
Guarantee Obligations Balance On Fourth Anniversary
46 
Guarantee Obligations Balance On Fifth Anniversary
31 
Guarantee Obligations Due After Five Years
242 
Guarantor Obligations, Maximum Exposure, Undiscounted
$ 1,012 
Segment and Significant Customer Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue from External Customer
 
 
 
 
 
 
 
 
$ 6,301 
$ 5,478 
$ 6,800 
Intersegment revenue
 
 
 
 
 
 
 
 
0 
0 
0 
Operating revenues
1,438 
2,050 
1,572 
1,241 
1,367 
1,996 
879 
1,236 
6,301 
5,478 
6,800 
Commodity Margin
 
 
 
 
 
 
 
 
2,568 
2,538 1 2
2,474 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(3)3
(84)3
(33)3
Plant operating expense
 
 
 
 
 
 
 
 
895 
922 
904 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
609 
562 
550 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
136 
140 
131 
Other operating expenses
 
 
 
 
 
 
 
 
81 
78 
77 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
0 
(222)
0 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
(30)
(28)
(21)
Income from operations
151 
597 
122 
4 
295 
705 
(193)
195 
874 
1,002 
800 
Interest expense, net of interest income
 
 
 
 
 
 
 
 
690 
725 
751 
Loss on interest rate derivatives
 
 
 
 
 
 
 
 
0 
14 
145 
Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
164 
45 
115 
Income (loss) before income taxes and discontinued operations
 
 
 
 
 
 
 
 
20 
218 
(211)
Commodity Margin Riverside Energy Center
 
 
 
 
 
 
 
 
 
73 
70 
Commodity Margin Broad River Energy Center
 
 
 
 
 
 
 
 
 
52 
51 
Lease levelization
 
 
 
 
 
 
 
 
6 
1 
12 
Contract amortization
 
 
 
 
 
 
 
 
14 
14 
8 
Number of significant customers
 
 
 
 
 
 
 
 
two 
one 
 
West [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue from External Customer
 
 
 
 
 
 
 
 
1,937 
1,668 
2,372 
Intersegment revenue
 
 
 
 
 
 
 
 
5 
10 
12 
Operating revenues
 
 
 
 
 
 
 
 
1,942 
1,678 
2,384 
Commodity Margin
 
 
 
 
 
 
 
 
1,020 
994 1 2
1,061 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(50)3
(93)3
113 3
Plant operating expense
 
 
 
 
 
 
 
 
365 
368 
380 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
243 
203 
192 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
37 
36 
43 
Other operating expenses
 
 
 
 
 
 
 
 
45 
42 
41 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
0 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
0 
Income from operations
 
 
 
 
 
 
 
 
280 
252 
518 
Texas [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue from External Customer
 
 
 
 
 
 
 
 
2,347 
1,857 
2,306 
Intersegment revenue
 
 
 
 
 
 
 
 
(4)
61 
23 
Operating revenues
 
 
 
 
 
 
 
 
2,343 
1,918 
2,329 
Commodity Margin
 
 
 
 
 
 
 
 
632 
570 1 2
469 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
51 3
87 3
(102)3
Plant operating expense
 
 
 
 
 
 
 
 
269 
247 
235 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
165 
142 
135 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
56 
47 
43 
Other operating expenses
 
 
 
 
 
 
 
 
3 
5 
3 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
0 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
0 
Income from operations
 
 
 
 
 
 
 
 
190 
216 
(49)
North [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue from External Customer
 
 
 
 
 
 
 
 
1,356 
1,280 
1,336 
Intersegment revenue
 
 
 
 
 
 
 
 
33 
14 
7 
Operating revenues
 
 
 
 
 
 
 
 
1,389 
1,294 
1,343 
Commodity Margin
 
 
 
 
 
 
 
 
712 
729 1 2
704 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
5 3
(14)3
(13)3
Plant operating expense
 
 
 
 
 
 
 
 
172 
206 
177 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
130 
134 
138 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
21 
28 
24 
Other operating expenses
 
 
 
 
 
 
 
 
29 
29 
30 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
(7)
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
(30)
(28)
(21)
Income from operations
 
 
 
 
 
 
 
 
395 
353 
343 
Southeast [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue from External Customer
 
 
 
 
 
 
 
 
661 
673 
786 
Intersegment revenue
 
 
 
 
 
 
 
 
189 
80 
135 
Operating revenues
 
 
 
 
 
 
 
 
850 
753 
921 
Commodity Margin
 
 
 
 
 
 
 
 
204 
245 1 2
240 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
22 3
(33)3
1 3
Plant operating expense
 
 
 
 
 
 
 
 
120 
131 
141 
Depreciation and amortization expense
 
 
 
 
 
 
 
 
73 
85 
90 
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
21 
29 
22 
Other operating expenses
 
 
 
 
 
 
 
 
4 
5 
5 
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
(215)
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
0 
Income from operations
 
 
 
 
 
 
 
 
8 
177 
(17)
Consolidation and Elimination [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenue from External Customer
 
 
 
 
 
 
 
 
0 
0 
0 
Intersegment revenue
 
 
 
 
 
 
 
 
(223)
(165)
(177)
Operating revenues
 
 
 
 
 
 
 
 
(223)
(165)
(177)
Commodity Margin
 
 
 
 
 
 
 
 
0 
0 1 2
0 1 2
Add: Mark-to-market commodity activity, net and other
 
 
 
 
 
 
 
 
(31)3
(31)3
(32)3
Plant operating expense
 
 
 
 
 
 
 
 
(31)
(30)
(29)
Depreciation and amortization expense
 
 
 
 
 
 
 
 
(2)
(2)
(5)
Sales, general and other administrative expense
 
 
 
 
 
 
 
 
1 
0 
(1)
Other operating expenses
 
 
 
 
 
 
 
 
0 
(3)
(2)
Gain (Loss) on Disposition of Assets
 
 
 
 
 
 
 
 
 
0 
 
(Income) from unconsolidated investments in power plants
 
 
 
 
 
 
 
 
0 
0 
0 
Income from operations
 
 
 
 
 
 
 
 
1 
4 
5 
PJM Settlement, Inc. [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
820 
713 
742 
Major customer receivables
 
 
 
 
 
 
 
 
26 
37 
 
Pacific Gas & Electric Company [Member]
 
 
 
 
 
 
 
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
694 
 
 
Major customer receivables
 
 
 
 
 
 
 
 
$ 83 
 
 
Quarterly Consolidated Financial Data (unaudited) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2013
Sep. 30, 2013
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 1,438 
$ 2,050 
$ 1,572 
$ 1,241 
$ 1,367 
$ 1,996 
$ 879 
$ 1,236 
$ 6,301 
$ 5,478 
$ 6,800 
Income (loss) from operations
151 
597 
122 
4 
295 
705 
(193)
195 
874 
1,002 
800 
Net income (loss) attributable to Calpine
$ (97)
$ 306 
$ (70)
$ (125)
$ 100 
$ 437 
$ (329)
$ (9)
$ 14 
$ 199 
$ (190)
Net income (loss) per common share attributable to Calpine — basic (in dollars per share)
$ (0.23)
$ 0.70 
$ (0.16)
$ (0.28)
$ 0.22 
$ 0.95 
$ (0.69)
$ (0.02)
$ 0.03 
$ 0.43 
$ (0.39)
Net income (loss) per common share attributable to Calpine — diluted (in dollars per share)
$ (0.23)
$ 0.70 
$ (0.16)
$ (0.28)
$ 0.22 
$ 0.94 
$ (0.69)
$ (0.02)
$ 0.03 
$ 0.42 
$ (0.39)
Schedule of Valuation and Qualifying Accounts Disclosure (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Allowance for Doubtful Accounts [Member]
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Balance at Beginning of Year
$ 6 
$ 13 
$ 2 
Charged to Expense
4 
(1)
7 
Deductions
0 1
(5)1
0 1
Charged to Other Accounts
(5)
(1)
4 
Balance at End of Year
5 
6 
13 
Deferred Tax Asset Valuation Allowance [Member]
 
 
 
Movement in Valuation Allowances and Reserves [Roll Forward]
 
 
 
Balance at Beginning of Year
2,222 
2,336 
2,386 
Charged to Expense
24 
(114)
(50)
Deductions
0 1
0 1
0 1
Charged to Other Accounts
0 
0 
0 
Balance at End of Year
$ 2,246 
$ 2,222 
$ 2,336