CALPINE CORP, 10-Q filed on 11/7/2013
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2013
Nov. 5, 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-Q 
 
Document Period End Date
Sep. 30, 2013 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q3 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
435,207,726 
Consolidated Condensed Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Operating revenues:
 
 
 
 
Commodity revenue
$ 2,020 
$ 1,689 
$ 4,867 
$ 4,078 
Unrealized mark-to-market gain (loss)
26 
304 
(14)
24 
Other revenue
4 
3 
10 
9 
Operating revenues
2,050 
1,996 
4,863 
4,111 
Operating expenses:
 
 
 
 
Commodity expense
1,076 
812 
2,909 
2,073 
Unrealized mark-to-market (gain) loss
(17)
85 
(29)
73 
Fuel and purchased energy expense
1,059 
897 
2,880 
2,146 
Plant operating expense
200 
207 
684 
699 
Depreciation and amortization expense
150 
140 
441 
418 
Sales, general and other administrative expense
33 
36 
102 
104 
Other operating expenses
20 
18 
58 
58 
Total operating expenses
1,462 
1,298 
4,165 
3,425 
(Income) from unconsolidated investments in power plants
(9)
(7)
(25)
(21)
Income from operations
597 
705 
723 
707 
Interest expense
176 
183 
522 
552 
Loss on interest rate derivatives
0 
0 
0 
14 
Interest (income)
(2)
(2)
(5)
(7)
Debt extinguishment costs
0 
0 
68 
12 
Other (income) expense, net
7 
6 
15 
14 
Income before income taxes
416 
518 
123 
122 
Income tax expense
110 
81 
12 
23 
Net income
306 
437 
111 
99 
Net income attributable to the noncontrolling interest
0 
0 
0 
0 
Net income attributable to Calpine
$ 306 
$ 437 
$ 111 
$ 99 
Basic earnings per common share attributable to Calpine:
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
434,384 
462,307 
444,486 
470,589 
Net income per common share attributable to Calpine — basic
$ 0.70 
$ 0.95 
$ 0.25 
$ 0.21 
Earnings Per Share, Diluted [Abstract]
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
438,493 
465,953 
448,546 
474,131 
Net income per common share attributable to Calpine — diluted
$ 0.70 
$ 0.94 
$ 0.25 
$ 0.21 
Consolidated Condensed Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income
$ 306 
$ 437 
$ 111 
$ 99 
Cash flow hedging activities:
 
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income
(7)
(22)
35 
(56)
Reclassification adjustment for (gain) loss on cash flow hedges realized in net income
19 
(1)
38 
(15)
Foreign currency translation gain (loss)
2 
6 
(5)
5 
Income tax (expense) benefit
(7)
3 
(4)
7 
Other comprehensive income (loss)
7 
(14)
64 
(59)
Comprehensive income
313 
423 
175 
40 
Comprehensive income attributable to the noncontrolling interest
0 
0 
0 
0 
Comprehensive income attributable to Calpine
$ 313 
$ 423 
$ 175 
$ 40 
Consolidated Condensed Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Current assets:
 
 
Cash and cash equivalents ($171 and $109 attributable to VIEs)
$ 1,024 
$ 1,284 
Accounts receivable, net of allowance of $1 and $6
657 
437 
Margin deposits and other prepaid expense
343 
244 
Restricted cash, current ($93 and $53 attributable to VIEs)
185 
193 
Derivative assets, current
471 
339 
Inventory and other current assets
355 
335 
Total current assets
3,035 
2,832 
Property, plant and equipment, net ($4,638 and $4,192 attributable to VIEs)
13,039 
13,005 
Restricted cash, net of current portion ($63 and $59 attributable to VIEs)
63 
60 
Investments in power plants
95 
81 
Long-term derivative assets
148 
98 
Other assets
423 
473 
Total assets
16,803 
16,549 
Current liabilities:
 
 
Accounts payable
451 
382 
Accrued interest payable
123 
180 
Debt, current portion ($89 and $39 attributable to VIEs)
154 
115 
Derivative liabilities, current
472 
357 
Other current liabilities
284 
284 
Total current liabilities
1,484 
1,318 
Debt, net of current portion ($2,942 and $2,660 attributable to VIEs)
10,869 
10,635 
Long-term derivative liabilities
333 
293 
Other long-term liabilities
317 
247 
Total liabilities
13,003 
12,493 
Commitments and contingencies (see Note 10)
   
   
Stockholders’ equity:
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding
0 
0 
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 497,754,264 and 492,495,100 shares issued, respectively, and 437,262,887 and 457,048,970 shares outstanding, respectively
1 
1 
Treasury stock, at cost, 60,491,377 and 35,446,130 shares, respectively
(1,069)
(594)
Additional paid-in capital
12,380 
12,335 
Accumulated deficit
(7,389)
(7,500)
Accumulated other comprehensive loss
(184)
(248)
Total Calpine stockholders’ equity
3,739 
3,994 
Noncontrolling interest
61 
62 
Total stockholders’ equity
3,800 
4,056 
Total liabilities and stockholders’ equity
$ 16,803 
$ 16,549 
Consolidated Condensed Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Cash and Cash Equivalents, at Carrying Value
$ 1,024 
$ 1,284 
Allowance for Doubtful Accounts Receivable, Current
1 
6 
Restricted cash, current ($93 and $53 attributable to VIEs)
185 
193 
Property, plant and equipment, net ($4,638 and $4,192 attributable to VIEs)
13,039 
13,005 
Restricted cash, net of current portion ($63 and $59 attributable to VIEs)
63 
60 
Debt, Current
154 
115 
Debt, net of current portion ($2,942 and $2,660 attributable to VIEs)
10,869 
10,635 
Preferred Stock, Par or Stated Value Per Share
$ 0.001 
$ 0.001 
Preferred Stock, Shares Authorized
100,000,000 
100,000,000 
Preferred Stock, Shares Issued
0 
0 
Preferred Stock, Shares Outstanding
0 
0 
Common Stock, Par or Stated Value Per Share
$ 0.001 
$ 0.001 
Common Stock, Shares Authorized
1,400,000,000 
1,400,000,000 
Common Stock, Shares, Issued
497,754,264 
492,495,100 
Common Stock, Shares, Outstanding
437,262,887 
457,048,970 
Treasury Stock, Shares
60,491,377 
35,446,130 
Variable Interest Entity, Primary Beneficiary [Member]
 
 
Cash and Cash Equivalents, at Carrying Value
171 
109 
Restricted cash, current ($93 and $53 attributable to VIEs)
93 
53 
Property, plant and equipment, net ($4,638 and $4,192 attributable to VIEs)
4,638 
4,192 
Restricted cash, net of current portion ($63 and $59 attributable to VIEs)
63 
59 
Debt, Current
89 
39 
Debt, net of current portion ($2,942 and $2,660 attributable to VIEs)
$ 2,942 
$ 2,660 
Consolidated Condensed Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Cash flows from operating activities:
 
 
Net income
$ 111 
$ 99 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization expense(1)
474 1
449 1
Debt extinguishment costs
28 
0 
Deferred income taxes
18 
(7)
Loss on disposition of assets
5 
10 
Unrealized mark-to-market activity, net
(14)2
(103)2
(Income) from unconsolidated investments in power plants
(25)
(21)
Return on unconsolidated investments in power plants
23 
20 
Stock-based compensation expense
28 
19 
Other
(2)
1 
Change in operating assets and liabilities:
 
 
Accounts receivable
(219)
96 
Derivative instruments, net
47 
(114)
Other assets
(111)
97 
Accounts payable and accrued expenses
(11)
(119)
Settlement of non-hedging interest rate swaps
0 
156 
Other liabilities
63 
25 
Net cash provided by operating activities
415 
608 
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(472)
(509)
Settlement of non-hedging interest rate swaps
0 
(156)
Return of investment in unconsolidated investment in power plants
1 
5 
(Increase) decrease in restricted cash
5 
(32)
Purchases of deferred transmission credits
0 
(12)
Other
(2)
3 
Net cash used in investing activities
(468)
(701)
Cash flows from financing activities:
 
 
Repayment under First Lien Term Loans
(19)
(12)
Borrowings from CCFC Term Loans
1,197 
0 
Repayments under CCFC Term Loans
(3)
0 
Repayment of CCFC Notes
(1,000)
0 
Borrowings from project financing, notes payable and other
139 
312 
Repayments of project financing, notes payable and other
(51)
(53)
Financing costs
(27)
(6)
Stock repurchases
(462)
(308)
Proceeds from exercises of stock options
19 
4 
Other
0 
1 
Net cash used in financing activities
(207)
(62)
Net decrease in cash and cash equivalents
(260)
(155)
Cash and cash equivalents, beginning of period
1,284 
1,252 
Cash and cash equivalents, end of period
1,024 
1,097 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
547 
565 
Income taxes
22 
14 
Supplemental disclosure of non-cash investing activities:
 
 
Change in capital expenditures included in accounts payable
10 
(3)
Additions to property, plant and equipment through assumption of long-term note payable
$ 0 
$ 8 
Basis of Presentation and Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Basis of Presentation and Summary of Significant Accounting Policies
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 primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2012, included in our 2012 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Reclassifications — Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the period ended September 30, 2012, to conform to the current period presentation. Our reclassifications are summarized as follows:
•
We have reclassified environmental compliance expense, primarily related to costs to comply with the Regional Greenhouse Gas Initiative in the Northeast, previously recorded in other operating expenses of $4 million and $9 million to Commodity expense on our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2012, respectively.
•
We have reclassified $4 million on our Consolidated Condensed Statement of Cash Flows for the nine months ended September 30, 2012, to separately report proceeds from the exercises of stock options, previously reflected in other cash flows used in financing activities.
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 September 30, 2013 and December 31, 2012, cash and cash equivalents included $195 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 Condensed Balance Sheets and Statements of Cash Flows.
The table below represents the components of our restricted cash as of September 30, 2013 and December 31, 2012 (in millions):

 
September 30, 2013
 
December 31, 2012
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
19

 
$
43

 
$
62

 
$
11

 
$
41

 
$
52

Rent reserve
4

 
—

 
4

 
—

 
—

 
—

Construction/major maintenance
26

 
11

 
37

 
32

 
14

 
46

Security/project/insurance
131

 
7

 
138

 
101

 
3

 
104

Other
5

 
2

 
7

 
49

 
2

 
51

Total
$
185

 
$
63

 
$
248

 
$
193

 
$
60

 
$
253

___________
(1)
At September 30, 2013 and December 31, 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.
Inventory — At September 30, 2013 and December 31, 2012, we had inventory of $325 million and $301 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Property, Plant and Equipment, Net — At September 30, 2013 and December 31, 2012, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
September 30, 2013
 
December 31, 2012
 
Depreciable Lives
Buildings, machinery and equipment(1)
$
15,862

 
$
14,774

 
3 – 47 Years
Geothermal properties
1,256

 
1,243

 
13 – 59 Years
Other
155

 
142

 
3 – 47 Years
 
17,273

 
16,159

 
 
Less: Accumulated depreciation
4,768

 
4,390

 
 
 
12,505

 
11,769

 
 
Land
103

 
98

 
 
Construction in progress(1)
431

 
1,138

 
 
Property, plant and equipment, net
$
13,039

 
$
13,005

 
 
___________
(1)
The change from December 31, 2012 to September 30, 2013 can primarily be attributed to our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013.
Capitalized Interest — The total amount of interest capitalized was $9 million and $10 million for the three months ended September 30, 2013 and 2012, respectively, and $33 million and $27 million for the nine months ended September 30, 2013 and 2012, respectively.
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 September 30, 2013 are as follows (in millions):
2013
$
142

2014
644

2015
660

2016
602

2017
566

Thereafter
3,110

Total
$
5,724


Treasury Stock — During the nine months ended September 30, 2013, we repurchased common stock with a value of $462 million and withheld shares with a value of $13 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees and net share employee stock options exercises under the Equity Plan.
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 5 for disclosures regarding our assets and liabilities that are presented gross on our Consolidated Condensed 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 5 for disclosures on the affect of significant reclassifications out of AOCI on the respective line items on our Consolidated Condensed 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.
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments in Power Plants
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 nine months ended September 30, 2013. See Note 5 in our 2012 Form 10-K for further information regarding our VIEs.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 9,027 MW and 8,255 MW at September 30, 2013 and December 31, 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, Calpine Corporation did not provide any support to these VIEs in the form of cash and other contributions during each of the three and nine months ended September 30, 2013 and 2012.
U.S. GAAP requires separate disclosure on the face of our Consolidated Condensed Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider 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 Condensed Balance Sheets. At September 30, 2013 and December 31, 2012, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
September 30, 2013
 
September 30, 2013
 
December 31, 2012
Greenfield LP
50%
 
$
81

 
$
69

Whitby
50%
 
14

 
12

Total investments in power plants
 
 
$
95

 
$
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 Condensed Balance Sheets. At September 30, 2013 and December 31, 2012, equity method investee debt was approximately $415 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 $208 million and $224 million at September 30, 2013 and December 31, 2012, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the three and nine months ended September 30, 2013 and 2012, 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 for the periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Greenfield LP
$
(5
)
 
$
(5
)
 
$
(14
)
 
$
(13
)
Whitby
(4
)
 
(2
)
 
(11
)
 
(8
)
Total
$
(9
)
 
$
(7
)
 
$
(25
)
 
$
(21
)

Distributions from Greenfield LP were $8 million and $15 million during the three and nine months ended September 30, 2013, respectively, and $9 million and $18 million during the three and nine months ended September 30, 2012, respectively. Distributions from Whitby were nil and $9 million during the three and nine months ended September 30, 2013, respectively, and nil and $7 million during the three and nine months ended September 30, 2012, respectively.
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.
Debt
Debt
Debt
At September 30, 2013 and December 31, 2012, our debt was as follows (in millions):
 
September 30, 2013

December 31, 2012
First Lien Notes
$
5,304

 
$
5,303

First Lien Term Loans
2,444

 
2,463

Project financing, notes payable and other
1,870

 
1,789

CCFC Term Loans
1,194

 
—

CCFC Notes
—

 
978

Capital lease obligations
211

 
217

Total debt
11,023

 
10,750

Less: Current maturities
154

 
115

Debt, net of current portion
$
10,869

 
$
10,635


Our effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, decreased to 6.7% for the nine months ended September 30, 2013, from 7.4% for the nine months ended September 30, 2012. The issuance of our 2019 First Lien Term Loan in October 2012 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and variable rate project debt with a corporate level term loan carrying a lower variable interest rate. Also, in February 2013, we repriced our First Lien Term Loans by lowering the LIBOR floor by 0.25% to 1.0% and lowering the margin over LIBOR by 0.25% to 3.0%. The issuance of the CCFC Term Loans in June 2013 also allowed us to reduce our interest expense by replacing the CCFC Notes, carrying a higher fixed interest rate, with the CCFC Term Loans carrying a lower variable interest rate.
First Lien Notes
Our First Lien Notes are summarized in the table below (in millions):
 
September 30, 2013
 
December 31, 2012
2017 First Lien Notes(1)
$
1,080

 
$
1,080

2019 First Lien Notes(2)
360

 
360

2020 First Lien Notes(2)
984

 
983

2021 First Lien Notes(2)
1,800

 
1,800

2023 First Lien Notes(2)
1,080

 
1,080

Total First Lien Notes
$
5,304

 
$
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 expires on November 29, 2013 and we expect to purchase any 2017 First Lien Notes tendered prior to the expiration of the tender offer, and redeem any remaining 2017 First Lien Notes on December 2, 2013.
(2)
On October 31, 2013, we issued notice to the holders of our 2019 First Lien Notes, 2020 First Lien Notes, 2021 First Lien Notes and 2023 First Lien Notes of our intent to redeem 10% of the original aggregate principal amount at a redemption price of 103% of the principal amount redeemed, plus accrued and unpaid interest. The redemption is expected to be completed in the fourth quarter of 2013 using proceeds received from the issuance of the 2024 First Lien Notes described below.
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 a portion of the proceeds from the 2020 First Lien Term Loan to repay a portion of the 2017 First Lien Notes on October 31, 2013 in conjunction with the tender offer initiated on October 17, 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 expect to record approximately $11 million in deferred financing costs and approximately $43 million of debt extinguishment costs associated with the redemption premium and write-off of unamortized deferred financing costs during the fourth quarter of 2013 related to the repayment of our 2017 First Lien Notes.
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 intend to use 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 redemption is expected to be completed in the fourth quarter of 2013. 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 expect to record approximately $7 million in deferred financing costs and approximately $14 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):
 
September 30, 2013
 
December 31, 2012
2018 First Lien Term Loans
$
1,617

 
$
1,630

2019 First Lien Term Loan
827

 
833

Total First Lien Term Loans
$
2,444

 
$
2,463


2020 First Lien Term Loan
On October 23, 2013, we entered into our $390 million 2020 First Lien Term Loan. We used or will use the net proceeds received, together with the proceeds from the 2022 First Lien Notes to repay the 2017 First Lien Notes. We borrowed $50 million under our 2020 First Lien Term Loan on October 31, 2013 to partially fund the redemption of a portion of our 2017 First Lien Notes in connection with the tender offer initiated on October 17, 2013. We plan to borrow the remaining approximately $340 million under our 2020 First Lien Term Loan on November 29, 2013 to pay the consideration on the final settlement date of the tender offer in respect of our 2017 First Lien Notes and redeem any 2017 First Lien Notes not tendered in the tender offer, which is expected to occur on December 2, 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 expect to record approximately $5 million in deferred financing costs during the fourth quarter of 2013 related to the issuance of the 2020 First Lien Term Loan.
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 for the nine months ended September 30, 2013 which is comprised of $40 million of prepayment penalties and $28 million associated with the write-off of unamortized debt discount and deferred financing costs. We also recorded $15 million in new deferred financing costs on our Consolidated Condensed Balance Sheet during the second quarter of 2013 associated with the issuance of the CCFC Term Loans.
Corporate Revolving Facility and Other Letters of Credit Facilities
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 table below represents amounts issued under our letter of credit facilities at September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
 
December 31, 2012
Corporate Revolving Facility(1)
$
244

 
$
243

CDHI
229

 
253

Various project financing facilities
152

 
130

Total
$
625

 
$
626

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
CDHI
We have a $300 million letter of credit facility related to CDHI. 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 September 30, 2013, we had $4 million in 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 September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
 
December 31, 2012
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
5,652

 
$
5,304

 
$
5,863

 
$
5,303

First Lien Term Loans
2,446

 
2,444

 
2,489

 
2,463

Project financing, notes payable and other(1)
1,738

 
1,735

 
1,599

 
1,629

CCFC Term Loans
1,171

 
1,194

 
—

 
—

CCFC Notes
—

 
—

 
1,075

 
978

Total
$
11,007

 
$
10,677

 
$
11,026

 
$
10,373

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

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 Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Our cash equivalents are classified within level 1 of the fair value hierarchy.
Margin Deposits and Margin Deposits 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 September 30, 2013 and December 31, 2012, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2013
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,222

 
$
—

 
$
—

 
$
1,222

Margin deposits
302

 
—

 
—

 
302

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
505

 
—

 
—

 
505

Commodity forward contracts(2)
—

 
80

 
26

 
106

Interest rate swaps
—

 
8

 
—

 
8

Total assets
$
2,029

 
$
88

 
$
26

 
$
2,143

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
22

 
$
—

 
$
—

 
$
22

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
566

 
—

 
—

 
566

Commodity forward contracts(2)
—

 
85

 
10

 
95

Interest rate swaps
—

 
144

 
—

 
144

Total liabilities
$
588

 
$
229

 
$
10

 
$
827

 
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 September 30, 2013 and December 31, 2012, we had cash equivalents of $1,002 million and $1,274 million included in cash and cash equivalents and $220 million and $228 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
At September 30, 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 delivery locations for which observable market rate information is not available. 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 September 30, 2013 and December 31, 2012:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
September 30, 2013
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
11

 
Discounted cash flow
 
Market price (per MWh)
 
$25.61 — $52.98/MWh
 
 
 
 
 
 
 
 
 
 
 
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 periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Balance, beginning of period
$
13

 
$
(10
)
 
$
16

 
$
17

Realized and unrealized gains:
 
 
 
 
 
 
 
Included in net income:
 
 
 
 
 
 
 
Included in operating revenues(1)
7

 
1

 
8

 
3

Included in fuel and purchased energy expense(2)
1

 
1

 
—

 
1

Included in OCI
—

 
—

 
—

 
1

Purchases, issuances and settlements:
 
 
 
 
 
 
 
Purchases
—

 
—

 
—

 
—

Issuances
—

 
(1
)
 
—

 
(1
)
Settlements
(5
)
 
25

 
(8
)
 
(4
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
Transfers into level 3(4)
—

 
—

 
—

 
—

Transfers out of level 3(5)
—

 
—

 
—

 
(1
)
Balance, end of period
$
16

 
$
16

 
$
16

 
$
16

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

 
$
2

 
$
8

 
$
4

___________
(1)
For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(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 for each of the three and nine months ended September 30, 2013 and 2012.
(4)
There were no transfers out of level 2 into level 3 for each of the three and nine months ended September 30, 2013 and 2012.
(5)
There were no transfers out of level 3 into level 2 for the three and nine months ended September 30, 2013. We had nil and $1 million in gains transferred out of level 3 into level 2 for the three and nine months ended September 30, 2012, respectively, due to changes in market liquidity in various power markets.
Derivative Instruments
Derivative Instruments
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, 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 September 30, 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 September 30, 2013 and December 31, 2012, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
September 30, 2013
 
December 31, 2012
Power (MWh)
 
(25
)
 
(16
)
Natural gas (MMBtu)
 
(275
)
 
66

Interest rate swaps
 
$
1,594

 
$
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 September 30, 2013, was $10 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 Condensed Statements of Operations until the period of delivery. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-to-market gain/loss on our Consolidated Condensed 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 Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We report the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on commodity hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed 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 Condensed 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 Condensed Statement of Operations for the nine months ended September 30, 2012, and approximately $142 million reflected the realization of losses recorded in prior periods.
Derivatives Included on Our Consolidated Condensed Balance Sheets
During the first quarter of 2012, we de-designated our remaining commodity derivative cash flow hedges; therefore, as of September 30, 2013 and December 31, 2012, we do not have any designated commodity derivative cash flow hedges. The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
471

 
$
—

 
$
471

Long-term derivative assets
140

 
8

 
148

Total derivative assets
$
611

 
$
8

 
$
619

 
 
 
 
 
 
Current derivative liabilities
$
424

 
$
48

 
$
472

Long-term derivative liabilities
237

 
96

 
333

Total derivative liabilities
$
661

 
$
144

 
$
805

Net derivative liabilities
$
(50
)
 
$
(136
)
 
$
(186
)

 
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 liabilities
$
(17
)
 
$
(196
)
 
$
(213
)


 
September 30, 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
$
8

 
$
128

 
$
4

 
$
184

Total derivatives designated as cash flow hedging instruments
$
8

 
$
128

 
$
4

 
$
184

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
611

 
$
661

 
$
433

 
$
450

Interest rate swaps
—

 
16

 
—

 
16

Total derivatives not designated as hedging instruments
$
611

 
$
677

 
$
433

 
$
466

Total derivatives
$
619

 
$
805

 
$
437

 
$
650


We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed 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 September 30, 2013 and December 31, 2012 (in millions):
 
 
September 30, 2013
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
505

 
$
(454
)
 
$
(51
)
 
$
—

Commodity forward contracts
 
106

 
(73
)
 
—

 
33

Interest rate swaps
 
8

 
—

 
—

 
8

Total derivative assets
 
$
619

 
$
(527
)
 
$
(51
)
 
$
41

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(566
)
 
$
454

 
$
112

 
$
—

Commodity forward contracts
 
(95
)
 
73

 
1

 
(21
)
Interest rate swaps
 
(144
)
 
—

 
—

 
(144
)
Total derivative (liabilities)
 
$
(805
)
 
$
527

 
$
113

 
$
(165
)
Net derivative assets (liabilities)
 
$
(186
)
 
$
—

 
$
62

 
$
(124
)
 
 
December 31, 2012
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed 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 6 for a further discussion of our collateral.
Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of 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 Condensed Statements of Operations for the periods indicated (in millions):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Realized gain (loss)(1)
 
 
 
 
 
 
 
Commodity derivative instruments
$
27

 
$
113

 
$
60

 
$
325

Interest rate swaps
—

 
—

 
—

 
(157
)
Total realized gain (loss)
$
27

 
$
113

 
$
60

 
$
168

 
 
 
 
 
 
 
 
Unrealized gain (loss)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
43

 
$
219

 
$
15

 
$
(49
)
Interest rate swaps
(5
)
 
3

 
(1
)
 
152

Total unrealized gain (loss)
$
38

 
$
222

 
$
14

 
$
103

Total mark-to-market activity, net
$
65

 
$
335

 
$
74

 
$
271

___________
(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.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Realized and unrealized gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues
$
18

 
$
329

 
$
(41
)
 
$
149

Derivatives contracts included in fuel and purchased energy expense
52

 
3

 
116

 
127

Interest rate swaps included in interest expense
(5
)
 
3

 
(1
)
 
9

Loss on interest rate derivatives
—

 
—

 
—

 
(14
)
Total mark-to-market activity, net
$
65

 
$
335

 
$
74

 
$
271


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 periods indicated (in millions):
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(4)
 
2013
 
2012
 
2013
 
2012
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments(1):
 
 
 
 
 
 
 
 
 
Power derivative instruments
$
—

 
$
(24
)
 
$
—

 
$
24

 
Commodity revenue
Natural gas derivative instruments
—

 
15

 
—

 
(15
)
 
Commodity expense
Interest rate swaps(2)
12

 
(14
)
 
(19
)
(5) 
(8
)
 
Interest expense
Total(3)
$
12

 
$
(23
)
 
$
(19
)
 
$
1

 
 
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(4)
 
2013
 
2012
 
2013
 
2012
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments(1):
 
 
 
 
 
 
 
 
 
Power derivative instruments
$
—

 
$
(68
)
 
$
—

 
$
91

 
Commodity revenue
Natural gas derivative instruments
—

 
45

 
—

 
(53
)
 
Commodity expense
Interest rate swaps(2)
73

 
(48
)
 
(38
)
(5) 
(23
)
 
Interest expense
Total(3)
$
73

 
$
(71
)
 
$
(38
)
 
$
15

 
 
____________
(1)
There were no commodity derivative instruments designated as cash flow hedges during the three and nine months ended September 30, 2013. We recorded a gain on hedge ineffectiveness of nil and $2 million related to our commodity derivative instruments designated as cash flow hedges during the three and nine months ended September 30, 2012.
(2)
We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three and nine months ended September 30, 2013 and 2012.
(3)
We recorded income tax expense of $7 million and $4 million for the three and nine months ended September 30, 2013, respectively, and income tax benefits of $3 million and $7 million for the three and nine months ended September 30, 2012, respectively, in AOCI related to our cash flow hedging activities.
(4)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $173 million and $242 million at September 30, 2013 and December 31, 2012, respectively.
(5)
Includes a loss of $7 million that was reclassified from AOCI to interest expense for each of the three and nine months ended September 30, 2013 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 [Text Block]
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 September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
 
December 31, 2012
Margin deposits(1)
$
302

 
$
196

Natural gas and power prepayments
23

 
35

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
325

 
$
231

 
 
 
 
Letters of credit issued
$
505

 
$
484

First priority liens under power and natural gas agreements
18

 
14

First priority liens under interest rate swap agreements
148

 
206

Total letters of credit and first priority liens with our counterparties
$
671

 
$
704

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
22

 
$
11

Letters of credit posted with us by our counterparties
87

 
1

Total margin deposits and letters of credit posted with us by our counterparties
$
109

 
$
12

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed 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 5 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At September 30, 2013 and December 31, 2012, $307 million and $211 million, respectively, were included in margin deposits and other prepaid expense and $18 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.
Income Taxes
Income Taxes
Income Taxes
Income Tax Expense

The table below shows our consolidated income tax expense from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Income tax expense
$
110

 
$
81

 
$
12

 
$
23

Effective tax rate
26
%
 
16
%
 
10
%
 
19
%

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.
We continue to evaluate the remaining proposed adjustments received on our other Canadian subsidiary; however, based on our current analysis which is supported by our tax advisors, we believe that our transfer pricing positions and policies are appropriate, and we intend to challenge the CRA’s proposed adjustments. If we are unsuccessful in our challenge, any adjustment to Canadian taxable income would first be offset against the existing NOLs that are available; however, we do not believe any reassessment resulting in an adjustment to taxable income which is greater than our existing NOLs, or including interest or penalties which cannot be offset by existing NOLs, would have a material adverse effect on our financial condition, results of operations or cash flows.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we are unable to assume future profits; however, since our emergence from Chapter 11, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At September 30, 2013, we had unrecognized tax benefits of $67 million. If recognized, $19 million of our unrecognized tax benefits could impact the annual effective tax rate and $48 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $13 million for income tax matters at September 30, 2013. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Condensed Statements of Operations.
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. The IRS expects to issue 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.
Earnings (Loss) per Share
Earnings (Loss) per Share
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. Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2013 and 2012, are as follows (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Diluted weighted average shares calculation:
 
 
 
 
 
 
 
Weighted average shares outstanding (basic)
434,384

 
462,307

 
444,486

 
470,589

Share-based awards
4,109

 
3,646

 
4,060

 
3,542

Weighted average shares outstanding (diluted)
438,493

 
465,953

 
448,546

 
474,131


We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2013 and 2012, because they were anti-dilutive (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Share-based awards
5,063

 
9,356

 
5,062

 
11,677

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 September 30, 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 $8 million and $6 million for the three months ended September 30, 2013 and 2012, respectively, and $27 million and $19 million for the nine months ended September 30, 2013 and 2012, 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 nine months ended September 30, 2013 and 2012. At September 30, 2013, there was unrecognized compensation cost of $2 million related to options, $32 million related to restricted stock and $1 million related to restricted stock units, which is expected to be recognized over a weighted average period of 0.8 years for options, 1.3 years for restricted stock and 0.6 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 nine months ended September 30, 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
3,616,031

 
$
13.72

 
 
 
 
Forfeited
—

 
$
—

 
 
 
 
Expired
31,100

 
$
17.70

 
 
 
 
Outstanding — September 30, 2013
14,226,669

 
$
18.21

 
3.4
 
$
36

Exercisable — September 30, 2013
12,270,330

 
$
18.82

 
2.7
 
$
26

Vested and expected to vest – September 30, 2013
14,124,288

 
$
18.24

 
3.3
 
$
36


The total intrinsic value of our employee stock options exercised was $21 million and $1 million for the nine months ended September 30, 2013 and 2012, respectively. The total cash proceeds received from our employee stock options exercised was $19 million and $4 million for the nine months ended September 30, 2013 and 2012, respectively.
The fair value of options granted during the nine months ended September 30, 2013 and 2012, 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
Expected term (in years)(1)
6.5

 
 
6.5

 
Risk-free interest rate(2)
1.4

%
 
1.2 – 1.6

%
Expected volatility(3)
25.6

%
 
27.0 – 30.5

%
Dividend yield(4)
—

 
 
—

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

 
 
$
5.18

 
___________
(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 we do not anticipate any cash dividend payments on our common stock in the near future.
No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 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
1,770,448

 
$
18.46

Forfeited
135,684

 
$
16.14

Vested
1,142,292

 
$
11.83

Nonvested — September 30, 2013
4,626,509

 
$
16.49


The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2013 and 2012, was approximately $21 million and $19 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 nil and $1 million for the three and nine months ended September 30, 2013.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
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 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 September 30, 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).
 
Three Months Ended September 30, 2013
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
620

 
$
842

 
$
401

 
$
187

 
$
—

 
$
2,050

Intersegment revenues
1

 
(6
)
 
12

 
57

 
(64
)
 
—

Total operating revenues
$
621

 
$
836

 
$
413

 
$
244

 
$
(64
)
 
$
2,050

Commodity Margin
$
337

 
$
328

 
$
242

 
$
78

 
$
—

 
$
985

Add: Unrealized mark-to-market commodity activity, net and other(1)
16

 
(5
)
 
(3
)
 
6

 
(8
)
 
6

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
80

 
60

 
40

 
27

 
(7
)
 
200

Depreciation and amortization expense
57

 
42

 
33

 
18

 
—

 
150

Sales, general and other administrative expense
4

 
17

 
6

 
5

 
1

 
33

Other operating expenses
11

 
2

 
9

 
1

 
(3
)
 
20

(Income) from unconsolidated investments in power plants
—

 
—

 
(9
)
 
—

 
—

 
(9
)
Income from operations
201

 
202

 
160

 
33

 
1

 
597

Interest expense, net of interest income

 
 
 
 
 
 
 
 
 
174

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
7

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
416


 
Three Months Ended September 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
509

 
$
886

 
$
407

 
$
194

 
$
—

 
$
1,996

Intersegment revenues
2

 
(34
)
 
4

 
68

 
(40
)
 
—

Total operating revenues
$
511

 
$
852

 
$
411

 
$
262

 
$
(40
)
 
$
1,996

Commodity Margin(2)(3)
$
330

 
$
218

 
$
266

 
$
83

 
$
—

 
$
897

Add: Unrealized mark-to-market commodity activity, net and other(1)
(40
)
 
249

 
(26
)
 
27

 
(8
)
 
202

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
88

 
49

 
51

 
29

 
(10
)
 
207

Depreciation and amortization expense
52

 
35

 
33

 
21

 
(1
)
 
140

Sales, general and other administrative expense
9

 
12

 
8

 
8

 
(1
)
 
36

Other operating expenses
10

 
1

 
6

 
(1
)
 
2

 
18

(Income) from unconsolidated investments in power plants
—

 
—

 
(7
)
 
—

 
—

 
(7
)
Income from operations
131

 
370

 
149

 
53

 
2

 
705

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
181

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
6

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
518

 
Nine Months Ended September 30, 2013
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,482

 
$
1,820

 
$
1,055

 
$
506

 
$
—

 
$
4,863

Intersegment revenues
2

 
(24
)
 
27

 
161

 
(166
)
 
—

Total operating revenues
$
1,484

 
$
1,796

 
$
1,082

 
$
667

 
$
(166
)
 
$
4,863

Commodity Margin
$
737

 
$
537

 
$
543

 
$
162

 
$
—

 
$
1,979

Add: Unrealized mark-to-market commodity activity, net and other(4)
(2
)
 
18

 
(8
)
 
20

 
(24
)
 
4

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
261

 
224

 
130

 
92

 
(23
)
 
684

Depreciation and amortization expense
160

 
129

 
98

 
55

 
(1
)
 
441

Sales, general and other administrative expense
11

 
55

 
18

 
17

 
1

 
102

Other operating expenses
31

 
4

 
23

 
2

 
(2
)
 
58

(Income) from unconsolidated investments in power plants
—

 
—

 
(25
)
 
—

 
—

 
(25
)
Income from operations
272

 
143

 
291

 
16

 
1

 
723

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
517

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
83

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
123

 
Nine Months Ended September 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,183

 
$
1,430

 
$
974

 
$
524

 
$
—

 
$
4,111

Intersegment revenues
7

 
27

 
9

 
84

 
(127
)
 
—

Total operating revenues
$
1,190

 
$
1,457

 
$
983

 
$
608

 
$
(127
)
 
$
4,111

Commodity Margin(2)(3)
$
748

 
$
472

 
$
591

 
$
212

 
$
—

 
$
2,023

Add: Unrealized mark-to-market commodity activity, net and other(4)
(80
)
 
66

 
(17
)
 
(5
)
 
(22
)
 
(58
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
281

 
189

 
154

 
98

 
(23
)
 
699

Depreciation and amortization expense
151

 
104

 
100

 
66

 
(3
)
 
418

Sales, general and other administrative expense
23

 
36

 
22

 
23

 
—

 
104

Other operating expenses
30

 
4

 
21

 
2

 
1

 
58

(Income) from unconsolidated investments in power plants
—

 
—

 
(21
)
 
—

 
—

 
(21
)
Income from operations
183


205


298


18


3

 
707

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
545

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
14

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
26

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
122

_________
(1)
Includes $44 million and $16 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2013 and 2012, respectively.
(2)
Our North segment includes Commodity Margin of $32 million and $64 million for the three and nine months ended September 30, 2012 related to Riverside Energy Center, LLC, which was sold in December 2012.
(3)
Our Southeast segment includes Commodity Margin of $20 million and $44 million for the three and nine months ended September 30, 2012 related to Broad River, which was sold in December 2012.
(4)
Includes $17 million and $7 million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2013 and 2012, respectively.
Basis of Presentation and Summary of Significant Accounting Policies (Policies)
Basis of Interim Presentation 
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2012, included in our 2012 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements 
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Reclassifications 
Reclassifications — Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the period ended September 30, 2012, to conform to the current period presentation. Our reclassifications are summarized as follows:
•
We have reclassified environmental compliance expense, primarily related to costs to comply with the Regional Greenhouse Gas Initiative in the Northeast, previously recorded in other operating expenses of $4 million and $9 million to Commodity expense on our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2012, respectively.
•
We have reclassified $4 million on our Consolidated Condensed Statement of Cash Flows for the nine months ended September 30, 2012, to separately report proceeds from the exercises of stock options, previously reflected in other cash flows used in financing activities.
Cash and Cash Equivalents 
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 September 30, 2013 and December 31, 2012, cash and cash equivalents included $195 million and $131 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash 
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.
Inventory 
Inventory — At September 30, 2013 and December 31, 2012, we had inventory of $325 million and $301 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Derivatives 
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-to-market gain/loss on our Consolidated Condensed 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 Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We report the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on commodity hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed 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 Condensed 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).
Commitments and Contingencies 
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.
Basis of Presentation and Summary of Significant Accounting Policies (Tables)
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block] 
The total contractual future minimum lease rentals for our contracts accounted for as operating leases at September 30, 2013 are as follows (in millions):
2013
$
142

2014
644

2015
660

2016
602

2017
566

Thereafter
3,110

Total
$
5,724

Schedule of Components of Restricted Cash 
The table below represents the components of our restricted cash as of September 30, 2013 and December 31, 2012 (in millions):

 
September 30, 2013
 
December 31, 2012
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
19

 
$
43

 
$
62

 
$
11

 
$
41

 
$
52

Rent reserve
4

 
—

 
4

 
—

 
—

 
—

Construction/major maintenance
26

 
11

 
37

 
32

 
14

 
46

Security/project/insurance
131

 
7

 
138

 
101

 
3

 
104

Other
5

 
2

 
7

 
49

 
2

 
51

Total
$
185

 
$
63

 
$
248

 
$
193

 
$
60

 
$
253

___________
(1)
At September 30, 2013 and December 31, 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 Property, Plant and Equipment 
Property, Plant and Equipment, Net — At September 30, 2013 and December 31, 2012, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
September 30, 2013
 
December 31, 2012
 
Depreciable Lives
Buildings, machinery and equipment(1)
$
15,862

 
$
14,774

 
3 – 47 Years
Geothermal properties
1,256

 
1,243

 
13 – 59 Years
Other
155

 
142

 
3 – 47 Years
 
17,273

 
16,159

 
 
Less: Accumulated depreciation
4,768

 
4,390

 
 
 
12,505

 
11,769

 
 
Land
103

 
98

 
 
Construction in progress(1)
431

 
1,138

 
 
Property, plant and equipment, net
$
13,039

 
$
13,005

 
 
___________
(1)
The change from December 31, 2012 to September 30, 2013 can primarily be attributed to our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013.
Variable Interest Entities and Unconsolidated Investments (Tables)
Income (Loss) From Unconsolidated Investments in Power Plants and Distributions 
Our equity interest in the net income from Greenfield LP and Whitby for the three and nine months ended September 30, 2013 and 2012, 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 for the periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Greenfield LP
$
(5
)
 
$
(5
)
 
$
(14
)
 
$
(13
)
Whitby
(4
)
 
(2
)
 
(11
)
 
(8
)
Total
$
(9
)
 
$
(7
)
 
$
(25
)
 
$
(21
)

Schedule of Equity Method Investments 
At September 30, 2013 and December 31, 2012, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
September 30, 2013
 
September 30, 2013
 
December 31, 2012
Greenfield LP
50%
 
$
81

 
$
69

Whitby
50%
 
14

 
12

Total investments in power plants
 
 
$
95

 
$
81

Debt (Tables)
Schedule of Long-term Debt Instruments 
At September 30, 2013 and December 31, 2012, our debt was as follows (in millions):
 
September 30, 2013

December 31, 2012
First Lien Notes
$
5,304

 
$
5,303

First Lien Term Loans
2,444

 
2,463

Project financing, notes payable and other
1,870

 
1,789

CCFC Term Loans
1,194

 
—

CCFC Notes
—

 
978

Capital lease obligations
211

 
217

Total debt
11,023

 
10,750

Less: Current maturities
154

 
115

Debt, net of current portion
$
10,869

 
$
10,635

First Lien Notes 
Our First Lien Notes are summarized in the table below (in millions):
 
September 30, 2013
 
December 31, 2012
2017 First Lien Notes(1)
$
1,080

 
$
1,080

2019 First Lien Notes(2)
360

 
360

2020 First Lien Notes(2)
984

 
983

2021 First Lien Notes(2)
1,800

 
1,800

2023 First Lien Notes(2)
1,080

 
1,080

Total First Lien Notes
$
5,304

 
$
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 expires on November 29, 2013 and we expect to purchase any 2017 First Lien Notes tendered prior to the expiration of the tender offer, and redeem any remaining 2017 First Lien Notes on December 2, 2013.
(2)
On October 31, 2013, we issued notice to the holders of our 2019 First Lien Notes, 2020 First Lien Notes, 2021 First Lien Notes and 2023 First Lien Notes of our intent to redeem 10% of the original aggregate principal amount at a redemption price of 103% of the principal amount redeemed, plus accrued and unpaid interest. The redemption is expected to be completed in the fourth quarter of 2013 using proceeds received from the issuance of the 2024 First Lien Notes described below.
First Lien Term Loans 
Our First Lien Term Loans are summarized in the table below (in millions):
 
September 30, 2013
 
December 31, 2012
2018 First Lien Term Loans
$
1,617

 
$
1,630

2019 First Lien Term Loan
827

 
833

Total First Lien Term Loans
$
2,444

 
$
2,463

Schedule of Line of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
 
December 31, 2012
Corporate Revolving Facility(1)
$
244

 
$
243

CDHI
229

 
253

Various project financing facilities
152

 
130

Total
$
625

 
$
626

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments 
The following table details the fair values and carrying values of our debt instruments at September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
 
December 31, 2012
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
5,652

 
$
5,304

 
$
5,863

 
$
5,303

First Lien Term Loans
2,446

 
2,444

 
2,489

 
2,463

Project financing, notes payable and other(1)
1,738

 
1,735

 
1,599

 
1,629

CCFC Term Loans
1,171

 
1,194

 
—

 
—

CCFC Notes
—

 
—

 
1,075

 
978

Total
$
11,007

 
$
10,677

 
$
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, Measurement Inputs, Disclosure 
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 September 30, 2013 and December 31, 2012, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2013
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,222

 
$
—

 
$
—

 
$
1,222

Margin deposits
302

 
—

 
—

 
302

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
505

 
—

 
—

 
505

Commodity forward contracts(2)
—

 
80

 
26

 
106

Interest rate swaps
—

 
8

 
—

 
8

Total assets
$
2,029

 
$
88

 
$
26

 
$
2,143

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
22

 
$
—

 
$
—

 
$
22

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
566

 
—

 
—

 
566

Commodity forward contracts(2)
—

 
85

 
10

 
95

Interest rate swaps
—

 
144

 
—

 
144

Total liabilities
$
588

 
$
229

 
$
10

 
$
827

 
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 September 30, 2013 and December 31, 2012, we had cash equivalents of $1,002 million and $1,274 million included in cash and cash equivalents and $220 million and $228 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
Fair Value Inputs, Liabilities, Quantitative Information 
At September 30, 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 delivery locations for which observable market rate information is not available. 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 September 30, 2013 and December 31, 2012:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
September 30, 2013
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
11

 
Discounted cash flow
 
Market price (per MWh)
 
$25.61 — $52.98/MWh
 
 
 
 
 
 
 
 
 
 
 
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, 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 periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Balance, beginning of period
$
13

 
$
(10
)
 
$
16

 
$
17

Realized and unrealized gains:
 
 
 
 
 
 
 
Included in net income:
 
 
 
 
 
 
 
Included in operating revenues(1)
7

 
1

 
8

 
3

Included in fuel and purchased energy expense(2)
1

 
1

 
—

 
1

Included in OCI
—

 
—

 
—

 
1

Purchases, issuances and settlements:
 
 
 
 
 
 
 
Purchases
—

 
—

 
—

 
—

Issuances
—

 
(1
)
 
—

 
(1
)
Settlements
(5
)
 
25

 
(8
)
 
(4
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
Transfers into level 3(4)
—

 
—

 
—

 
—

Transfers out of level 3(5)
—

 
—

 
—

 
(1
)
Balance, end of period
$
16

 
$
16

 
$
16

 
$
16

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

 
$
2

 
$
8

 
$
4

___________
(1)
For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(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 for each of the three and nine months ended September 30, 2013 and 2012.
(4)
There were no transfers out of level 2 into level 3 for each of the three and nine months ended September 30, 2013 and 2012.
(5)
There were no transfers out of level 3 into level 2 for the three and nine months ended September 30, 2013. We had nil and $1 million in gains transferred out of level 3 into level 2 for the three and nine months ended September 30, 2012, respectively, due to changes in market liquidity in various power markets.
Derivative Instruments (Tables)
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block] 
The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
471

 
$
—

 
$
471

Long-term derivative assets
140

 
8

 
148

Total derivative assets
$
611

 
$
8

 
$
619

 
 
 
 
 
 
Current derivative liabilities
$
424

 
$
48

 
$
472

Long-term derivative liabilities
237

 
96

 
333

Total derivative liabilities
$
661

 
$
144

 
$
805

Net derivative liabilities
$
(50
)
 
$
(136
)
 
$
(186
)

 
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 liabilities
$
(17
)
 
$
(196
)
 
$
(213
)
Schedule of Notional Amounts of Outstanding Derivative Positions 
As of September 30, 2013 and December 31, 2012, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
September 30, 2013
 
December 31, 2012
Power (MWh)
 
(25
)
 
(16
)
Natural gas (MMBtu)
 
(275
)
 
66

Interest rate swaps
 
$
1,594

 
$
1,602

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value 
 
September 30, 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
$
8

 
$
128

 
$
4

 
$
184

Total derivatives designated as cash flow hedging instruments
$
8

 
$
128

 
$
4

 
$
184

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
611

 
$
661

 
$
433

 
$
450

Interest rate swaps
—

 
16

 
—

 
16

Total derivatives not designated as hedging instruments
$
611

 
$
677

 
$
433

 
$
466

Total derivatives
$
619

 
$
805

 
$
437

 
$
650

Derivative Instruments Subject to Master Netting Arrangements [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 September 30, 2013 and December 31, 2012 (in millions):
 
 
September 30, 2013
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
505

 
$
(454
)
 
$
(51
)
 
$
—

Commodity forward contracts
 
106

 
(73
)
 
—

 
33

Interest rate swaps
 
8

 
—

 
—

 
8

Total derivative assets
 
$
619

 
$
(527
)
 
$
(51
)
 
$
41

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(566
)
 
$
454

 
$
112

 
$
—

Commodity forward contracts
 
(95
)
 
73

 
1

 
(21
)
Interest rate swaps
 
(144
)
 
—

 
—

 
(144
)
Total derivative (liabilities)
 
$
(805
)
 
$
527

 
$
113

 
$
(165
)
Net derivative assets (liabilities)
 
$
(186
)
 
$
—

 
$
62

 
$
(124
)
 
 
December 31, 2012
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed 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 6 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 Condensed Statements of Operations for the periods indicated (in millions):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Realized gain (loss)(1)
 
 
 
 
 
 
 
Commodity derivative instruments
$
27

 
$
113

 
$
60

 
$
325

Interest rate swaps
—

 
—

 
—

 
(157
)
Total realized gain (loss)
$
27

 
$
113

 
$
60

 
$
168

 
 
 
 
 
 
 
 
Unrealized gain (loss)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
43

 
$
219

 
$
15

 
$
(49
)
Interest rate swaps
(5
)
 
3

 
(1
)
 
152

Total unrealized gain (loss)
$
38

 
$
222

 
$
14

 
$
103

Total mark-to-market activity, net
$
65

 
$
335

 
$
74

 
$
271

___________
(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 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Realized and unrealized gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues
$
18

 
$
329

 
$
(41
)
 
$
149

Derivatives contracts included in fuel and purchased energy expense
52

 
3

 
116

 
127

Interest rate swaps included in interest expense
(5
)
 
3

 
(1
)
 
9

Loss on interest rate derivatives
—

 
—

 
—

 
(14
)
Total mark-to-market activity, net
$
65

 
$
335

 
$
74

 
$
271

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 periods indicated (in millions):
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(4)
 
2013
 
2012
 
2013
 
2012
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments(1):
 
 
 
 
 
 
 
 
 
Power derivative instruments
$
—

 
$
(24
)
 
$
—

 
$
24

 
Commodity revenue
Natural gas derivative instruments
—

 
15

 
—

 
(15
)
 
Commodity expense
Interest rate swaps(2)
12

 
(14
)
 
(19
)
(5) 
(8
)
 
Interest expense
Total(3)
$
12

 
$
(23
)
 
$
(19
)
 
$
1

 
 
 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(4)
 
2013
 
2012
 
2013
 
2012
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments(1):
 
 
 
 
 
 
 
 
 
Power derivative instruments
$
—

 
$
(68
)
 
$
—

 
$
91

 
Commodity revenue
Natural gas derivative instruments
—

 
45

 
—

 
(53
)
 
Commodity expense
Interest rate swaps(2)
73

 
(48
)
 
(38
)
(5) 
(23
)
 
Interest expense
Total(3)
$
73

 
$
(71
)
 
$
(38
)
 
$
15

 
 
____________
(1)
There were no commodity derivative instruments designated as cash flow hedges during the three and nine months ended September 30, 2013. We recorded a gain on hedge ineffectiveness of nil and $2 million related to our commodity derivative instruments designated as cash flow hedges during the three and nine months ended September 30, 2012.
(2)
We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three and nine months ended September 30, 2013 and 2012.
(3)
We recorded income tax expense of $7 million and $4 million for the three and nine months ended September 30, 2013, respectively, and income tax benefits of $3 million and $7 million for the three and nine months ended September 30, 2012, respectively, in AOCI related to our cash flow hedging activities.
(4)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $173 million and $242 million at September 30, 2013 and December 31, 2012, respectively.
(5)
Includes a loss of $7 million that was reclassified from AOCI to interest expense for each of the three and nine months ended September 30, 2013 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 September 30, 2013 and December 31, 2012 (in millions):
 
September 30, 2013
 
December 31, 2012
Margin deposits(1)
$
302

 
$
196

Natural gas and power prepayments
23

 
35

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
325

 
$
231

 
 
 
 
Letters of credit issued
$
505

 
$
484

First priority liens under power and natural gas agreements
18

 
14

First priority liens under interest rate swap agreements
148

 
206

Total letters of credit and first priority liens with our counterparties
$
671

 
$
704

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
22

 
$
11

Letters of credit posted with us by our counterparties
87

 
1

Total margin deposits and letters of credit posted with us by our counterparties
$
109

 
$
12

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed 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 5 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At September 30, 2013 and December 31, 2012, $307 million and $211 million, respectively, were included in margin deposits and other prepaid expense and $18 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
Income Taxes Income Taxes (Tables)
Schedule of Components of Income Tax Expense (Benefit)
The table below shows our consolidated income tax expense from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Income tax expense
$
110

 
$
81

 
$
12

 
$
23

Effective tax rate
26
%
 
16
%
 
10
%
 
19
%
Earnings (Loss) per Share (Tables)
Schedule of Weighted Average Number of Shares [Table Text Block] 
Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2013 and 2012, are as follows (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Diluted weighted average shares calculation:
 
 
 
 
 
 
 
Weighted average shares outstanding (basic)
434,384

 
462,307

 
444,486

 
470,589

Share-based awards
4,109

 
3,646

 
4,060

 
3,542

Weighted average shares outstanding (diluted)
438,493

 
465,953

 
448,546

 
474,131

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share 
We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2013 and 2012, because they were anti-dilutive (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Share-based awards
5,063

 
9,356

 
5,062

 
11,677

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 nine months ended September 30, 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
3,616,031

 
$
13.72

 
 
 
 
Forfeited
—

 
$
—

 
 
 
 
Expired
31,100

 
$
17.70

 
 
 
 
Outstanding — September 30, 2013
14,226,669

 
$
18.21

 
3.4
 
$
36

Exercisable — September 30, 2013
12,270,330

 
$
18.82

 
2.7
 
$
26

Vested and expected to vest – September 30, 2013
14,124,288

 
$
18.24

 
3.3
 
$
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
Expected term (in years)(1)
6.5

 
 
6.5

 
Risk-free interest rate(2)
1.4

%
 
1.2 – 1.6

%
Expected volatility(3)
25.6

%
 
27.0 – 30.5

%
Dividend yield(4)
—

 
 
—

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

 
 
$
5.18

 
___________
(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 we do not anticipate any cash dividend payments 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 nine months ended September 30, 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
1,770,448

 
$
18.46

Forfeited
135,684

 
$
16.14

Vested
1,142,292

 
$
11.83

Nonvested — September 30, 2013
4,626,509

 
$
16.49

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).
 
Three Months Ended September 30, 2013
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
620

 
$
842

 
$
401

 
$
187

 
$
—

 
$
2,050

Intersegment revenues
1

 
(6
)
 
12

 
57

 
(64
)
 
—

Total operating revenues
$
621

 
$
836

 
$
413

 
$
244

 
$
(64
)
 
$
2,050

Commodity Margin
$
337

 
$
328

 
$
242

 
$
78

 
$
—

 
$
985

Add: Unrealized mark-to-market commodity activity, net and other(1)
16

 
(5
)
 
(3
)
 
6

 
(8
)
 
6

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
80

 
60

 
40

 
27

 
(7
)
 
200

Depreciation and amortization expense
57

 
42

 
33

 
18

 
—

 
150

Sales, general and other administrative expense
4

 
17

 
6

 
5

 
1

 
33

Other operating expenses
11

 
2

 
9

 
1

 
(3
)
 
20

(Income) from unconsolidated investments in power plants
—

 
—

 
(9
)
 
—

 
—

 
(9
)
Income from operations
201

 
202

 
160

 
33

 
1

 
597

Interest expense, net of interest income

 
 
 
 
 
 
 
 
 
174

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
7

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
416


 
Three Months Ended September 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
509

 
$
886

 
$
407

 
$
194

 
$
—

 
$
1,996

Intersegment revenues
2

 
(34
)
 
4

 
68

 
(40
)
 
—

Total operating revenues
$
511

 
$
852

 
$
411

 
$
262

 
$
(40
)
 
$
1,996

Commodity Margin(2)(3)
$
330

 
$
218

 
$
266

 
$
83

 
$
—

 
$
897

Add: Unrealized mark-to-market commodity activity, net and other(1)
(40
)
 
249

 
(26
)
 
27

 
(8
)
 
202

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
88

 
49

 
51

 
29

 
(10
)
 
207

Depreciation and amortization expense
52

 
35

 
33

 
21

 
(1
)
 
140

Sales, general and other administrative expense
9

 
12

 
8

 
8

 
(1
)
 
36

Other operating expenses
10

 
1

 
6

 
(1
)
 
2

 
18

(Income) from unconsolidated investments in power plants
—

 
—

 
(7
)
 
—

 
—

 
(7
)
Income from operations
131

 
370

 
149

 
53

 
2

 
705

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
181

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
6

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
518

 
Nine Months Ended September 30, 2013
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,482

 
$
1,820

 
$
1,055

 
$
506

 
$
—

 
$
4,863

Intersegment revenues
2

 
(24
)
 
27

 
161

 
(166
)
 
—

Total operating revenues
$
1,484

 
$
1,796

 
$
1,082

 
$
667

 
$
(166
)
 
$
4,863

Commodity Margin
$
737

 
$
537

 
$
543

 
$
162

 
$
—

 
$
1,979

Add: Unrealized mark-to-market commodity activity, net and other(4)
(2
)
 
18

 
(8
)
 
20

 
(24
)
 
4

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
261

 
224

 
130

 
92

 
(23
)
 
684

Depreciation and amortization expense
160

 
129

 
98

 
55

 
(1
)
 
441

Sales, general and other administrative expense
11

 
55

 
18

 
17

 
1

 
102

Other operating expenses
31

 
4

 
23

 
2

 
(2
)
 
58

(Income) from unconsolidated investments in power plants
—

 
—

 
(25
)
 
—

 
—

 
(25
)
Income from operations
272

 
143

 
291

 
16

 
1

 
723

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
517

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
83

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
123

 
Nine Months Ended September 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,183

 
$
1,430

 
$
974

 
$
524

 
$
—

 
$
4,111

Intersegment revenues
7

 
27

 
9

 
84

 
(127
)
 
—

Total operating revenues
$
1,190

 
$
1,457

 
$
983

 
$
608

 
$
(127
)
 
$
4,111

Commodity Margin(2)(3)
$
748

 
$
472

 
$
591

 
$
212

 
$
—

 
$
2,023

Add: Unrealized mark-to-market commodity activity, net and other(4)
(80
)
 
66

 
(17
)
 
(5
)
 
(22
)
 
(58
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
281

 
189

 
154

 
98

 
(23
)
 
699

Depreciation and amortization expense
151

 
104

 
100

 
66

 
(3
)
 
418

Sales, general and other administrative expense
23

 
36

 
22

 
23

 
—

 
104

Other operating expenses
30

 
4

 
21

 
2

 
1

 
58

(Income) from unconsolidated investments in power plants
—

 
—

 
(21
)
 
—

 
—

 
(21
)
Income from operations
183


205


298


18


3

 
707

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
545

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
14

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
26

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
122

_________
(1)
Includes $44 million and $16 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2013 and 2012, respectively.
(2)
Our North segment includes Commodity Margin of $32 million and $64 million for the three and nine months ended September 30, 2012 related to Riverside Energy Center, LLC, which was sold in December 2012.
(3)
Our Southeast segment includes Commodity Margin of $20 million and $44 million for the three and nine months ended September 30, 2012 related to Broad River, which was sold in December 2012.
(4)
Includes $17 million and $7 million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2013 and 2012, respectively.
Basis of Presentation and Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Dec. 31, 2012
Accounting Policies [Line Items]
 
 
 
 
 
Held-to-maturity Securities, Restricted
$ 24 
 
$ 24 
 
$ 25 
Current
185 
 
185 
 
193 
Non-current
63 
 
63 
 
60 
Total
248 
 
248 
 
253 
Cash and cash equivalents subject to project finance facilities and lease agreements
195 
 
195 
 
131 
Interest Costs Capitalized
9 
10 
33 
27 
 
Inventory
325 
 
325 
 
301 
Treasury Stock, Value, Acquired, Cost Method
 
 
462 
 
 
Adjustments Related to Tax Withholding for Share-based Compensation
 
 
13 
 
 
Debt Service
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
19 1
 
19 1
 
11 1
Non-current
43 1
 
43 1
 
41 1
Total
62 1
 
62 1
 
52 1
Rent Reserve
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
4 
 
4 
 
0 
Non-current
0 
 
0 
 
0 
Total
4 
 
4 
 
0 
Construction Major Maintenance
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
26 
 
26 
 
32 
Non-current
11 
 
11 
 
14 
Total
37 
 
37 
 
46 
Security Project Insurance
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
131 
 
131 
 
101 
Non-current
7 
 
7 
 
3 
Total
138 
 
138 
 
104 
Other
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
5 
 
5 
 
49 
Non-current
2 
 
2 
 
2 
Total
7 
 
7 
 
51 
Geothermal Properties, Gross [Member] |
Minimum [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
 
 
13 years 
 
 
Geothermal Properties, Gross [Member] |
Maximum [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
 
 
59 years 
 
 
Property, Plant and Equipment, Other Types [Member] |
Minimum [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
 
 
3 years 
 
 
Property, Plant and Equipment, Other Types [Member] |
Maximum [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
 
 
47 years 
 
 
Building, Machinery and Equipment, Gross [Member] |
Minimum [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
 
 
3 years 
 
 
Building, Machinery and Equipment, Gross [Member] |
Maximum [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Property, Plant and Equipment, Estimated Useful Lives
 
 
47 years 
 
 
Income Statement [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Prior Period Reclassification Adjustment
 
4 
 
9 
 
Cash Flow Statement [Member]
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Prior Period Reclassification Adjustment
 
 
 
$ 4 
 
Basis of Presentation and Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Property, Plant and Equipment [Line Items]
 
 
Buildings, machinery and equipment
$ 15,862 1
$ 14,774 1
Geothermal properties
1,256 
1,243 
Other
155 
142 
Property, Plant and Equipment, Gross
17,273 
16,159 
Less: Accumulated depreciation
4,768 
4,390 
Property, Plant and Equipment, Gross, Less Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
12,505 
11,769 
Land
103 
98 
Construction in progress
431 
1,138 
Property, plant and equipment, net
$ 13,039 
$ 13,005 
Basis of Presentation and Summary of Significant Accounting Policies Future Minimum Lease Rentals (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Operating Leases [Abstract]
 
Operating Leases, Future Minimum Payments Receivable, Current
$ 142 
Operating Leases, Future Minimum Payments Receivable, in Two Years
644 
Operating Leases, Future Minimum Payments Receivable, in Three Years
660 
Operating Leases, Future Minimum Payments Receivable, in Four Years
602 
Operating Leases, Future Minimum Payments Receivable, in Five Years
566 
Operating Leases, Future Minimum Payments Receivable, Thereafter
3,110 
Operating Leases, Future Minimum Payments Receivable
$ 5,724 
Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 95 
$ 81 
Greenfield [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
81 
69 
Equity Method Investment, Ownership Percentage
50.00% 
 
Whitby [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 14 
$ 12 
Equity Method Investment, Ownership Percentage
50.00% 
 
Variable Interest Entities and Unconsolidated Investments (Income from Unconsolidated Investements 10-Q) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
(Income) from unconsolidated investments in power plants
$ (9)
$ (7)
$ (25)
$ (21)
Greenfield [Member]
 
 
 
 
(Income) from unconsolidated investments in power plants
(5)
(5)
(14)
(13)
Whitby [Member]
 
 
 
 
(Income) from unconsolidated investments in power plants
$ (4)
$ (2)
$ (11)
$ (8)
Variable Interest Entities and Unconsolidated Investments (VIE Texuals) (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2013
MW
Sep. 30, 2012
Sep. 30, 2013
MW
Sep. 30, 2012
Dec. 31, 2012
MW
Variable Interest Entity [Line Items]
 
 
 
 
 
Power generation capacity
9,027 
 
9,027 
 
8,255 
Variable Interest Entity, Financial or Other Support, Amount
$ 0 
$ 0 
$ 0 
$ 0 
 
Equity Method Investment, Summarized Financial Information, Debt
415,000,000 
 
415,000,000 
 
448,000,000 
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt
208,000,000 
 
208,000,000 
 
224,000,000 
Greenfield [Member]
 
 
 
 
 
Variable Interest Entity [Line Items]
 
 
 
 
 
Power generation capacity
1,038 
 
1,038 
 
 
Equity Method Investment, Ownership Percentage
50.00% 
 
50.00% 
 
 
Distribution from equity method investee
8,000,000 
9,000,000 
15,000,000 
18,000,000 
 
Whitby [Member]
 
 
 
 
 
Variable Interest Entity [Line Items]
 
 
 
 
 
Power generation capacity
50 
 
50 
 
 
Equity Method Investment, Ownership Percentage
50.00% 
 
50.00% 
 
 
Distribution from equity method investee
$ 0 
$ 0 
$ 9,000,000 
$ 7,000,000 
 
Inland Empire Energy Center [Member]
 
 
 
 
 
Variable Interest Entity [Line Items]
 
 
 
 
 
Power generation capacity
775 
 
775 
 
 
Put Option Exercise Period
2,025 
 
2,025 
 
 
Inland Empire Energy Center [Member] |
Minimum [Member]
 
 
 
 
 
Variable Interest Entity [Line Items]
 
 
 
 
 
Call Option Exercise Period
2,017 
 
2,017 
 
 
Inland Empire Energy Center [Member] |
Maximum [Member]
 
 
 
 
 
Variable Interest Entity [Line Items]
 
 
 
 
 
Call Option Exercise Period
2,024 
 
2,024 
 
 
Debt (Debt) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,023 
$ 10,750 
Debt, Current
154 
115 
Long-term Debt, Excluding Current Maturities
(10,869)
(10,635)
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
5,304 
5,303 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,444 
2,463 
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,870 
1,789 
CCFC Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,194 
0 
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 
978 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 211 
$ 217 
Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Sep. 30, 2013
First Lien Notes 2017 [Member]
Dec. 31, 2012
First Lien Notes 2017 [Member]
Sep. 30, 2013
First Lien Notes 2019 [Member]
Dec. 31, 2012
First Lien Notes 2019 [Member]
Sep. 30, 2013
First Lien Notes 2020 [Member]
Dec. 31, 2012
First Lien Notes 2020 [Member]
Sep. 30, 2013
First Lien Notes 2021 [Member]
Dec. 31, 2012
First Lien Notes 2021 [Member]
Sep. 30, 2013
First Lien Notes 2023 [Member]
Dec. 31, 2012
First Lien Notes 2023 [Member]
Sep. 30, 2013
Corporate Debt Securities [Member]
Dec. 31, 2012
Corporate Debt Securities [Member]
Dec. 31, 2013
Early Tender Amount [Member]
First Lien Notes 2017 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt
$ 11,023 
$ 10,750 
$ 1,080 1
$ 1,080 1
$ 360 2
$ 360 2
$ 984 2
$ 983 2
$ 1,800 2
$ 1,800 2
$ 1,080 2
$ 1,080 2
$ 5,304 
$ 5,303 
$ 742 1
Debt (First Lien Term Loans) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,023 
$ 10,750 
First Lien Term Loans 2018 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,617 
1,630 
First Lien Term Loan 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
827 
833 
First Lien Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 2,444 
$ 2,463 
Debt (Letter of Credit) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 625 
$ 626 
Corporate Revolving Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
244 1
243 1
CDH [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
229 
253 
Various Project Financing Facilities [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 152 
$ 130 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Portion at Fair Value, Fair Value Disclosure [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
$ 5,652 
$ 5,863 
Subsidiaries Notes Disclosure
0 
1,075 
Notes Payable, Other Payables, Disclosure
1,738 1
1,599 1
Subsidiaries Term Loan
1,171 
0 
Loans Payable, Fair Value Disclosure
2,446 
2,489 
Debt Excluding Capital Leases
11,007 
11,026 
Carrying (Reported) Amount, Fair Value Disclosure [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
5,304 
5,303 
Subsidiaries Notes Disclosure
0 
978 
Notes Payable, Other Payables, Disclosure
1,735 1
1,629 1
Subsidiaries Term Loan
1,194 
0 
Loans Payable, Fair Value Disclosure
2,444 
2,463 
Debt Excluding Capital Leases
$ 10,677 
$ 10,373 
Debt (Debt Textuals) (Details) (USD $)
3 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
First Lien Term Loans [Member]
Sep. 30, 2013
CCFC Term Loan B-1 [Member]
Sep. 30, 2013
CCFC Term Loan B-2 [Member]
Sep. 30, 2013
CCFC Notes [Member]
Jun. 30, 2013
CCFC Notes [Member]
Sep. 30, 2013
CCFC Term Loans [Member]
Sep. 30, 2013
Corporate Revolving Facility [Member]
Sep. 30, 2013
Corporate Revolving Facility Amendment No. 1 [Member]
Sep. 30, 2013
CDHI [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage
 
 
 
 
 
 
 
 
 
 
0.75% 
0.50% 
 
Debt Instrument, Face Amount
 
 
 
 
 
$ 900,000,000 
$ 300,000,000 
$ 1,000,000,000 
 
 
 
 
 
Term Loan Period
 
 
 
 
 
7 years 
8 years 6 months 
 
 
 
 
 
 
Percentage of the principal amount of the Term Loan to be paid quarterly
 
 
 
 
 
 
 
 
 
0.25% 
 
 
 
Debt Instrument, Redemption Price, Percentage
 
 
 
 
 
 
 
 
 
104.00% 
 
 
 
Term loan interest rate spread option Federal Funds effective rate
 
 
 
 
 
 
 
 
 
0.50% 
 
 
 
Term loan interest rate spread option Prime Rate
 
 
 
 
 
1.25% 
1.50% 
 
 
 
2.25% 
1.25% 
 
Debt Instrument, Interest Rate, Effective Percentage
6.70% 
7.40% 
6.70% 
7.40% 
 
 
 
 
 
 
 
 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
 
 
 
 
3.00% 
2.25% 
2.50% 
 
 
 
3.25% 
2.25% 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum
 
 
 
 
1.00% 
 
 
 
 
0.75% 
 
 
 
Long Term Debt net of Original Issuance Disount
 
 
 
 
 
 
 
 
 
99.75% 
 
 
 
Lowering the LIBOR margin due to repricing
 
 
 
 
0.25% 
 
 
 
 
 
 
 
 
Lowering the LIBOR floor due to repricing
 
 
 
 
0.25% 
 
 
 
 
 
 
 
 
Letter of Credit Total
 
 
 
 
 
 
 
 
 
 
 
 
300,000,000 
Letter of Credit Uncollateral Total
 
 
 
 
 
 
 
 
 
 
 
 
225,000,000 
Pledged Financial Instruments, Not Separately Reported, Securities for Letter of Credit Facilities
 
 
 
 
 
 
 
 
 
 
 
 
4,000,000 
Gains (Losses) on Extinguishment of Debt
0 
0 
(68,000,000)
(12,000,000)
 
 
 
 
 
 
 
 
 
Prepayment Penalties
 
 
 
 
 
 
 
40,000,000 
 
 
 
 
 
Write off of Deferred Debt Issuance Cost
 
 
 
 
 
 
 
28,000,000 
 
 
 
 
 
Deferred Finance Costs, Net
 
 
 
 
 
 
 
 
$ 15,000,000 
 
 
 
 
Debt 2020 First Lien Term Loan (Details) (2020 First Lien Term Loan [Member], USD $)
Dec. 31, 2013
Sep. 30, 2013
Debt Instrument [Line Items]
 
 
Debt Instrument, Face Amount
 
$ 390,000,000 
Deferred Finance Costs, Net
5,000,000 
 
Initial draw on 2020 First Lien Term Loan [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Face Amount
50,000,000 
 
Additional Draw on 2020 First Lien Term Note [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Face Amount
$ 340,000,000 
 
Debt 2022 First Lien Notes (Details) (USD $)
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Dec. 31, 2013
2022 First Lien Notes [Member]
Sep. 30, 2013
2022 First Lien Notes [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
 
$ 750,000,000 
Long Term Debt net of Original Issuance Disount
 
 
 
 
 
99.193% 
Deferred Finance Costs, Net
 
 
 
 
11,000,000 
 
Gains (Losses) on Extinguishment of Debt
$ 0 
$ 0 
$ (68,000,000)
$ (12,000,000)
$ 43,000,000 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
6.00% 
Debt 2024 First Lien Notes (Details) (USD $)
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Dec. 31, 2013
2024 First Lien Notes [Member]
Sep. 30, 2013
2024 First Lien Notes [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
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
 
 
 
 
$ 7,000,000 
 
Debt Instrument, Face Amount
 
 
 
 
 
490,000,000 
Gains (Losses) on Extinguishment of Debt
$ 0 
$ 0 
$ (68,000,000)
$ (12,000,000)
$ 14,000,000 
 
Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 1,222 1
$ 1,502 1
Margin deposits
302 2
196 2
Commodity futures contracts
505 
385 
Commodity forward contracts
106 3
48 3
Interest Rate Swap Assets, Fair Value Disclosure
8 
4 
Total assets
2,143 
2,135 
Margin deposits held by us posted by our counterparties
22 2 4
11 2 4
Commodity futures contracts
566 
424 
Commodity forward contracts
95 3
26 3
Interest rate swaps
144 
200 
Liabilities, Fair Value Disclosure
827 
661 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1,222 1
1,502 1
Margin deposits
302 
196 
Commodity futures contracts
505 
385 
Commodity forward contracts
0 3
0 3
Interest Rate Swap Assets, Fair Value Disclosure
0 
0 
Total assets
2,029 
2,083 
Margin deposits held by us posted by our counterparties
22 
11 
Commodity futures contracts
566 
424 
Commodity forward contracts
0 3
0 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
588 
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 deposits
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
80 3
24 3
Interest Rate Swap Assets, Fair Value Disclosure
8 
4 
Total assets
88 
28 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
85 3
18 3
Interest rate swaps
144 
200 
Liabilities, Fair Value Disclosure
229 
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 deposits
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
26 3
24 3
Interest Rate Swap Assets, Fair Value Disclosure
0 
0 
Total assets
26 
24 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
10 3
8 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
$ 10 
$ 8 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Balance, beginning of period
$ 13 
$ (10)
$ 16 
$ 17 
 
Included in net income:
 
 
 
 
 
Included in operating revenues
7 1
1 1
8 1
3 1
 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense
1 2
1 2
0 2
1 2
 
Included in OCI
0 
0 
0 
1 
 
Purchases, issuances and settlements:
 
 
 
 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases
0 
0 
0 
0 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issues
0 
(1)
0 
(1)
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements
(5)
25 
(8)
(4)
 
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount
0 
0 
0 
0 
 
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount
0 
0 
0 
0 
 
Transfers into level 3
0 3 4
0 3 4
0 3 4
0 3 4
 
Transfers out of Level 3
0 3 5
0 3 5
0 3 5
1 3 5
 
Balance, end of period
16 
16 
16 
16 
 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Change in Unrealized Gain (Loss) Held At Period End
8 
2 
8 
4 
 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
 
 
Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure
1,002 
 
1,002 
 
1,274 
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure
$ 220 
 
$ 220 
 
$ 228 
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) (USD $)
Sep. 30, 2013
Dec. 31, 2012
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
$ 25.61 
$ 23.75 
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
52.98 
53.82 
Physical Power [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
$ 11,000,000 
$ 11,000,000 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2013
MWh
MMBTU
Dec. 31, 2012
MWh
MMBTU
Derivative Instruments [Abstract]
 
 
Derivative, Nonmonetary Notional Amount, Energy Measure
(25)
(16)
Nonmonetary Notional Amount of Price Risk Derivatives Natural Gas
(275)
66 
Price Risk Derivatives [Abstract]
 
 
Derivative, Notional Amount
$ 1,594 
$ 1,602 
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
$ 471 
$ 339 
Derivative Assets, Noncurrent
148 
98 
Total derivative assets
619 
437 
Current derivative liabilities
472 
357 
Derivative Liabilities, Noncurrent
333 
293 
Total derivative liabilities
805 
650 
Net derivative assets (liabilities)
(186)
(213)
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
8 
4 
Total derivative liabilities
128 
184 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
611 
433 
Total derivative liabilities
677 
466 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
0 
0 
Derivative Assets, Noncurrent
8 
4 
Total derivative assets
8 
4 
Current derivative liabilities
48 
40 
Derivative Liabilities, Noncurrent
96 
160 
Total derivative liabilities
144 
200 
Net derivative assets (liabilities)
(136)
(196)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
8 
4 
Total derivative liabilities
128 
184 
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
0 
0 
Total derivative liabilities
16 
16 
Commodity Option [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
471 
339 
Derivative Assets, Noncurrent
140 
94 
Total derivative assets
611 
433 
Current derivative liabilities
424 
317 
Derivative Liabilities, Noncurrent
237 
133 
Total derivative liabilities
661 
450 
Net derivative assets (liabilities)
(50)
(17)
Commodity Option [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
611 
433 
Total derivative liabilities
$ 661 
$ 450 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Power contracts included in operating revenues
$ 18 
$ 329 
$ (41)
$ 149 
Natural gas contracts included in fuel and purchased energy expense
52 
3 
116 
127 
Interest rate swaps included in interest expense
(5)
3 
(1)
9 
Gain (Loss) on interest rate derivatives, net
0 
0 
0 
(14)
Gain (Loss) on Derivative Instruments, Net, Pretax
65 1
335 1
74 
271 
Gain (Loss) on Sale of Derivatives
27 
113 
60 1
168 1
Unrealized gain (loss)
38 1
222 1
14 2
103 2
Interest Rate Swap [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Gain (Loss) on Sale of Derivatives
0 1
0 1
0 1
(157)1
Unrealized gain (loss)
(5)2
3 2
(1)2
152 2
Commodity Option [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Gain (Loss) on Sale of Derivatives
27 
113 
60 1
325 1
Unrealized gain (loss)
$ 43 1
$ 219 1
$ 15 2
$ (49)2
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
$ 12 1
$ (23)1
$ 73 1
$ (71)1
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
(19)1 2
1 1 2
(38)1 2
15 1 2
Interest Rate Swap [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
12 3
(14)3
73 3
(48)3
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
(19)2 3 4
(8)2 3
(38)2 3 4
(23)2 3
Power Derivative Instruments [Member] |
Commodity Option [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
0 5
(24)5
0 5
(68)5
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
0 2 5
24 2 5
0 2 5
91 2 5
Natural Gas Derivative Instruments [Member] |
Commodity Option [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
0 5
15 5
0 5
45 5
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
$ 0 2 5
$ (15)2 5
$ 0 2 5
$ (53)2 5
Derivative Instruments (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 12 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Dec. 31, 2012
Derivatives, Fair Value [Line Items]
 
 
 
 
 
(Gain) Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Unrealized
 
 
 
$ 14 
 
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net
 
0 
 
2 
 
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax
7 
3 
4 
7 
 
Derivative Instruments (Textuals) [Abstract]
 
 
 
 
 
Maximum length of time hedging using interest rate derivative instruments
 
 
10 years 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
10 
 
10 
 
 
Collateral Already Posted, Aggregate Fair Value
1 
 
1 
 
 
Additional Collateral, Aggregate Fair Value
0 
 
0 
 
 
Cumulative cash flow hedge losses remaining in AOCI
 
 
173 
 
242 
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net
7 
 
7,000,000 
 
 
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months
 
 
43 
 
 
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
0 
0 
0 
(14)
 
Interest Rate Derivative Liabilities, Fair Value on Settlement Date [Line Items]
 
 
 
 
 
(Gain) Loss on Interest Rate Derivative Instruments Not Designated as Hedging Instruments, realized
 
 
 
142 
 
Interest Rate Swap [Member]
 
 
 
 
 
Derivative Instruments (Textuals) [Abstract]
 
 
 
 
 
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
 
 
 
$ 156 
 
Derivative Instruments (Detail 5) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net
$ (186)
$ (213)
Derivative Fair Value, Amount Not Offset Against Collateral, Net
0 
0 
Derivative Asset, Fair Value, Amount Offset Against Collateral
41 
34 
Derivative Asset, Fair Value, Gross Asset
619 
437 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(527)
(396)
Derivative Liability, Fair Value, Gross Liability
(805)
(650)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
527 
396 
Margin/Cash (Received) Posted Subject to Master Netting Arrangement
62 1
39 1
Derivative Liability, Fair Value, Amount Offset Against Collateral
(165)
(208)
Derivative, Fair Value, Amount Offset Against Collateral, Net
(124)
(174)
Derivative, Collateral, Right to Reclaim Cash
113 1
46 1
Derivative, Collateral, Obligation to Return Cash
(51)1
(7)1
Commodity Exchange Traded Futures and Swaps Contracts [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Amount Offset Against Collateral
0 
0 
Derivative Asset, Fair Value, Gross Asset
505 
385 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(454)
(379)
Derivative Liability, Fair Value, Gross Liability
(566)
(424)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
454 
379 
Derivative Liability, Fair Value, Amount Offset Against Collateral
0 
0 
Derivative, Collateral, Right to Reclaim Cash
112 1
45 1
Derivative, Collateral, Obligation to Return Cash
(51)1
(6)1
Commodity Forward Contract [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Amount Offset Against Collateral
33 
30 
Derivative Asset, Fair Value, Gross Asset
106 
48 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(73)
(17)
Derivative Liability, Fair Value, Gross Liability
(95)
(26)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
73 
17 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(21)
(8)
Derivative, Collateral, Right to Reclaim Cash
1 1
1 1
Derivative, Collateral, Obligation to Return Cash
0 1
(1)1
Interest Rate Swap [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net
(136)
(196)
Derivative Asset, Fair Value, Amount Offset Against Collateral
8 
4 
Derivative Asset, Fair Value, Gross Asset
8 
4 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
0 
0 
Derivative Liability, Fair Value, Gross Liability
(144)
(200)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
0 
0 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(144)
(200)
Derivative, Collateral, Right to Reclaim Cash
0 1
0 1
Derivative, Collateral, Obligation to Return Cash
$ 0 1
$ 0 1
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2013
Dec. 31, 2012
Use of Collateral [Abstract]
 
 
Margin deposits
$ 302 1
$ 196 1
Natural gas and power prepayments
23 
35 
Total margin deposits and natural gas and power prepayments with our counterparties
325 2
231 2
Letters of credit issued
505 
484 
First priority liens under power and natural gas agreements
18 
14 
First priority liens under interest rate swap agreements
148 
206 
Total letters of credit and first priority liens with our counterparties
671 
704 
Margin deposits held by us posted by our counterparties
22 1 3
11 1 3
Letters of credit posted with us by our counterparties
87 
1 
Total margin deposits and letters of credit posted with us by our counterparties
109 
12 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
18 
20 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
$ 307 
$ 211 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Income Tax Disclosure [Abstract]
 
 
 
 
Income tax (expense) benefit
$ (110)
$ (81)
$ (12)
$ (23)
Effective Income Tax Rate, Continuing Operations
26.00% 
16.00% 
10.00% 
19.00% 
Unrecognized Tax Benefits
67 
 
67 
 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
19 
 
19 
 
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward
48 
 
48 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
$ 13 
 
$ 13 
 
Earnings (Loss) per Share (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Earnings (Loss) per Share [Abstract]
 
 
 
 
Share-based awards
5,063 
9,356 
5,062 
11,677 
Earnings (Loss) per Share Reconcilation of Basic to Diluted Weighted Average Shares Outstanding (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Earnings Per Share [Abstract]
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
434,384 
462,307 
444,486 
470,589 
Weighted Average Number Diluted Shares Outstanding Adjustment
4,109 
3,646 
4,060 
3,542 
Weighted average shares of common stock outstanding (in thousands)
438,493 
465,953 
448,546 
474,131 
Stock-Based Compensation (Schedule of Non-qualified Stock Option Activity) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2013
Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
 
 
Options, Outstanding
14,226,669 
17,862,501 
Options, Outstanding, Weighted Average Exercise Price
$ 18.21 
$ 17.30 
Options, Outstanding, Weighted Average Remaining Contractual Term
3 years 4 months 26 days 
4 years 
Options, Outstanding, Intrinsic Value
$ 36 
$ 42 
Options, Grants in Period, Gross
11,299 
 
Options, Grants in Period, Weighted Average Exercise Price
$ 18.34 
 
Options, Exercises in Period
3,616,031 
 
Options, Exercises in Period, Weighted Average Exercise Price
$ 13.72 
 
Options, Forfeitures in Period
0 
 
Options, Forfeitures in Period, Weighted Average Exercise Price
$ 0.00 
 
Options, Expirations in Period
31,100 
 
Options, Expirations in Period, Weighted Average Exercise Price
$ 17.70 
 
Options, Exercisable
12,270,330 
 
Options, Exercisable, Weighted Average Exercise Price
$ 18.82 
 
Options, Exercisable, Weighted Average Remaining Contractual Term
2 years 8 months 13 days 
 
Options, Exercisable, Intrinsic Value
26 
 
Options, Vested and Expected to Vest, Outstanding
14,124,288 
 
Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price
$ 18.24 
 
Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term
3 years 3 months 20 days 
 
Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value
$ 36 
 
Stock-Based Compensation (Asummptions used to estimate fair value for options) (Details)
9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term
6 years 6 months 1
6 years 6 months 1
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
1.40% 2
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
25.60% 3
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate
0.00% 4
0.00% 4
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 5.31 
$ 5.18 
Minimum [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
 
1.20% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
 
27.00% 3
Maximum [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
 
1.60% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
 
30.50% 3
Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) (Restricted Stock [Member], USD $)
9 Months Ended
Sep. 30, 2013
Dec. 31, 2012
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, Nonvested, Number
4,626,509 
4,134,037 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 16.49 
$ 14.33 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
1,770,448 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 18.46 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
135,684 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value
$ 16.14 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
1,142,292 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 11.83 
 
Stock-Based Compensation (Stock Based Compensation Textuals) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
 
 
1.40% 1
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
 
 
25.60% 2
 
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 
 
567,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Employees
40,533,000 
 
40,533,000 
 
Percentage of sub-grants representing the total
33.33% 
 
33.33% 
 
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 
 
Allocated Share-based Compensation Expense
$ 8 
$ 6 
$ 27 
$ 19 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value
 
 
21 
1 
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options
 
 
19 
4 
Liability Classified Share-Based Awards
0 
 
1 
 
Minimum [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
 
 
 
1.20% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
 
 
 
27.00% 2
Maximum [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate
 
 
 
1.60% 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate
 
 
 
30.50% 2
Stock Options [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
2 
 
2 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
 
 
9 months 
 
Restricted Stock [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
32 
 
32 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
 
 
1 year 4 months 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
 
 
21 
19 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
 
 
1,770,448 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
 
 
$ 18.46 
 
Restricted Stock Units (RSUs) [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
$ 1 
 
$ 1 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
 
 
7 months 
 
Performance Shares [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, 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 
 
Segment and Significant Customer Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2013
Sep. 30, 2012
Sep. 30, 2013
Sep. 30, 2012
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenue from External Customer
$ 2,050 
$ 1,996 
$ 4,863 
$ 4,111 
Intersegment revenue
0 
0 
0 
0 
Operating revenues
2,050 
1,996 
4,863 
4,111 
Commodity Margin
985 
897 1 2
1,979 
2,023 1 2
Add: Mark-to-market commodity activity, net and other
6 3
202 3
4 4
(58)4
Plant operating expense
200 
207 
684 
699 
Depreciation and amortization expense
150 
140 
441 
418 
Sales, general and other administrative expense
33 
36 
102 
104 
Other operating expenses
20 
18 
58 
58 
(Income) loss from unconsolidated investments in power plants
(9)
(7)
(25)
(21)
Income from operations
597 
705 
723 
707 
Interest expense, net of interest income
174 
181 
517 
545 
Loss on interest rate derivatives
0 
0 
0 
14 
Debt Extinguishment Costs and Other (Income) Expense, Net
 
 
83 
26 
Debt Extinguishment Costs and Other (Income) Expense, Net
7 
6 
15 
14 
Income before income taxes
416 
518 
123 
122 
Lease levelization
44 
16 
17 
7 
Commodity Margin Riverside Energy Center
 
32 
 
64 
Commodity Margin Broad River Energy Center
 
20 
 
44 
Contract amortization
4 
4 
11 
11 
West [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenue from External Customer
620 
509 
1,482 
1,183 
Intersegment revenue
1 
2 
2 
7 
Operating revenues
621 
511 
1,484 
1,190 
Commodity Margin
337 
330 1 2
737 
748 1 2
Add: Mark-to-market commodity activity, net and other
16 3
(40)3
(2)4
(80)4
Plant operating expense
80 
88 
261 
281 
Depreciation and amortization expense
57 
52 
160 
151 
Sales, general and other administrative expense
4 
9 
11 
23 
Other operating expenses
11 
10 
31 
30 
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Income from operations
201 
131 
272 
183 
Texas [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenue from External Customer
842 
886 
1,820 
1,430 
Intersegment revenue
(6)
(34)
(24)
27 
Operating revenues
836 
852 
1,796 
1,457 
Commodity Margin
328 
218 1 2
537 
472 1 2
Add: Mark-to-market commodity activity, net and other
(5)3
249 3
18 4
66 4
Plant operating expense
60 
49 
224 
189 
Depreciation and amortization expense
42 
35 
129 
104 
Sales, general and other administrative expense
17 
12 
55 
36 
Other operating expenses
2 
1 
4 
4 
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Income from operations
202 
370 
143 
205 
North [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenue from External Customer
401 
407 
1,055 
974 
Intersegment revenue
12 
4 
27 
9 
Operating revenues
413 
411 
1,082 
983 
Commodity Margin
242 
266 1 2
543 
591 1 2
Add: Mark-to-market commodity activity, net and other
(3)3
(26)3
(8)4
(17)4
Plant operating expense
40 
51 
130 
154 
Depreciation and amortization expense
33 
33 
98 
100 
Sales, general and other administrative expense
6 
8 
18 
22 
Other operating expenses
9 
6 
23 
21 
(Income) loss from unconsolidated investments in power plants
(9)
(7)
(25)
(21)
Income from operations
160 
149 
291 
298 
Southeast [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenue from External Customer
187 
194 
506 
524 
Intersegment revenue
57 
68 
161 
84 
Operating revenues
244 
262 
667 
608 
Commodity Margin
78 
83 1 2
162 
212 1 2
Add: Mark-to-market commodity activity, net and other
6 3
27 3
20 4
(5)4
Plant operating expense
27 
29 
92 
98 
Depreciation and amortization expense
18 
21 
55 
66 
Sales, general and other administrative expense
5 
8 
17 
23 
Other operating expenses
1 
(1)
2 
2 
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Income from operations
33 
53 
16 
18 
Consolidation and Elimination [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenue from External Customer
0 
0 
0 
0 
Intersegment revenue
(64)
(40)
(166)
(127)
Operating revenues
(64)
(40)
(166)
(127)
Commodity Margin
0 
0 1 2
0 
0 1 2
Add: Mark-to-market commodity activity, net and other
(8)3
(8)3
(24)4
(22)4
Plant operating expense
(7)
(10)
(23)
(23)
Depreciation and amortization expense
0 
(1)
(1)
(3)
Sales, general and other administrative expense
1 
(1)
1 
0 
Other operating expenses
(3)
2 
(2)
1 
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Income from operations
$ 1 
$ 2 
$ 1 
$ 3