CALPINE CORP, 10-Q filed on 11/6/2014
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2014
Nov. 4, 2014
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, 2014 
 
Document Fiscal Year Focus
2014 
 
Document Fiscal Period Focus
Q3 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
389,569,531 
Consolidated Condensed Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Operating revenues:
 
 
 
 
Commodity revenue
$ 2,186 
$ 2,020 
$ 6,000 
$ 4,867 
Mark-to-market gain (loss)
(2)
26 
81 
(14)
Other revenue
3 
4 
10 
10 
Operating revenues
2,187 
2,050 
6,091 
4,863 
Operating expenses:
 
 
 
 
Commodity expense
1,281 
1,076 
3,757 
2,909 
Mark-to-market (gain) loss
(13)
(17)
2 
(29)
Fuel and purchased energy expense
1,268 
1,059 
3,759 
2,880 
Plant operating expense
215 
200 
754 
684 
Depreciation and amortization expense
153 
150 
453 
441 
Sales, general and other administrative expense
37 
33 
108 
102 
Other operating expenses
23 
20 
66 
58 
Total operating expenses
1,696 
1,462 
5,140 
4,165 
Impairment losses
123 
0 
123 
0 
(Gain) on sale of assets, net
(753)
0 
(753)
0 
(Income) from unconsolidated investments in power plants
(5)
(9)
(18)
(25)
Income from operations
1,126 
597 
1,599 
723 
Interest expense
156 
176 
491 
522 
Interest (income)
(2)
(2)
(5)
(5)
Debt extinguishment costs
340 
0 
341 
68 
Other (income) expense, net
4 
7 
20 
15 
Income before income taxes
628 
416 
752 
123 
Income tax expense
9 
110 
5 
12 
Net income
619 
306 
747 
111 
Net income attributable to the noncontrolling interest
(5)
0 
(11)
0 
Net income attributable to Calpine
$ 614 
$ 306 
$ 736 
$ 111 
Basic earnings per common share attributable to Calpine:
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
398,232 
434,384 
411,534 
444,486 
Net income per common share attributable to Calpine — basic
$ 1.54 
$ 0.70 
$ 1.79 
$ 0.25 
Diluted earnings per common share attributable to Calpine:
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
402,962 
438,493 
416,056 
448,546 
Net income per common share attributable to Calpine — diluted
$ 1.52 
$ 0.70 
$ 1.77 
$ 0.25 
Consolidated Condensed Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income
$ 619 
$ 306 
$ 747 
$ 111 
Cash flow hedging activities:
 
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income
3 
(7)
(32)
35 
Reclassification adjustment for loss on cash flow hedges realized in net income
8 
19 
34 
38 
Foreign currency translation gain (loss)
(7)
2 
(7)
(5)
Income tax expense
0 
(7)
0 
(4)
Other comprehensive income (loss)
4 
7 
(5)
64 
Comprehensive income
623 
313 
742 
175 
Comprehensive (income) attributable to the noncontrolling interest
(5)
(1)
(10)
(6)
Comprehensive income attributable to Calpine
$ 618 
$ 312 
$ 732 
$ 169 
Consolidated Condensed Balance Sheets (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Current assets:
 
 
Cash and cash equivalents ($198 and $242 attributable to VIEs)
$ 1,529 
$ 941 
Accounts receivable, net of allowance of $5 and $5
680 
552 
Inventories
353 
364 
Margin deposits and other prepaid expense
224 
309 
Restricted cash, current ($167 and $100 attributable to VIEs)
244 
203 
Derivative assets, current
549 
445 
Other current assets
37 
42 
Total current assets
3,616 
2,856 
Property, plant and equipment, net ($4,383 and $4,191 attributable to VIEs)
12,665 
12,995 
Restricted cash, net of current portion ($41 and $68 attributable to VIEs)
42 
69 
Investments in power plants
92 
93 
Long-term derivative assets
295 
105 
Other assets ($184 and $195 attributable to VIEs)
462 
441 
Total assets
17,172 
16,559 
Current liabilities:
 
 
Accounts payable
560 
462 
Accrued interest payable
95 
162 
Debt, current portion ($144 and $140 attributable to VIEs)
194 
204 
Derivative liabilities, current
534 
451 
Other current liabilities
377 
252 
Total current liabilities
1,760 
1,531 
Debt, net of current portion ($3,306 and $2,923 attributable to VIEs)
11,260 
10,908 
Long-term derivative liabilities
295 
243 
Other long-term liabilities
297 
309 
Total liabilities
13,612 
12,991 
Commitments and contingencies (see Note 12)
   
   
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, 502,233,764 and 497,841,056 shares issued, respectively, and 397,280,391 and 429,038,988 shares outstanding, respectively
1 
1 
Treasury stock, at cost, 104,953,373 and 68,802,068 shares, respectively
(2,011)
(1,230)
Additional paid-in capital
12,432 
12,389 
Accumulated deficit
(6,750)
(7,486)
Accumulated other comprehensive loss
(164)
(160)
Total Calpine stockholders’ equity
3,508 
3,514 
Noncontrolling interest
52 
54 
Total stockholders’ equity
3,560 
3,568 
Total liabilities and stockholders’ equity
$ 17,172 
$ 16,559 
Consolidated Condensed Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Cash and cash equivalents ($198 and $242 attributable to VIEs)
$ 1,529 
$ 941 
Allowance for Doubtful Accounts Receivable, Current
5 
5 
Restricted cash, current ($167 and $100 attributable to VIEs)
244 
203 
Property, plant and equipment, net ($4,383 and $4,191 attributable to VIEs)
12,665 
12,995 
Restricted cash, net of current portion ($41 and $68 attributable to VIEs)
42 
69 
Other assets ($184 and $195 attributable to VIEs)
462 
441 
Debt, current portion ($144 and $140 attributable to VIEs)
194 
204 
Debt, net of current portion ($3,306 and $2,923 attributable to VIEs)
11,260 
10,908 
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
502,233,764 
497,841,056 
Common Stock, Shares, Outstanding
397,280,391 
429,038,988 
Treasury Stock, Shares
104,953,373 
68,802,068 
Variable Interest Entity, Primary Beneficiary [Member]
 
 
Cash and cash equivalents ($198 and $242 attributable to VIEs)
198 
242 
Restricted cash, current ($167 and $100 attributable to VIEs)
167 
100 
Property, plant and equipment, net ($4,383 and $4,191 attributable to VIEs)
4,383 
4,191 
Restricted cash, net of current portion ($41 and $68 attributable to VIEs)
41 
68 
Other assets ($184 and $195 attributable to VIEs)
184 
195 
Debt, current portion ($144 and $140 attributable to VIEs)
144 
140 
Debt, net of current portion ($3,306 and $2,923 attributable to VIEs)
$ 3,306 
$ 2,923 
Consolidated Condensed Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Cash flows from operating activities:
 
 
Net income
$ 747 
$ 111 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization expense(1)
486 1
474 1
Debt extinguishment costs
35 
28 
Deferred income taxes
(9)
18 
Impairment losses
123 
0 
(Gain) on sale of assets, net
(753)
0 
Mark-to-market activity, net
(88)2
(14)2
(Income) from unconsolidated investments in power plants
(18)
(25)
Return on unconsolidated investments in power plants
13 
23 
Stock-based compensation expense
30 
28 
Other
0 
3 
Change in operating assets and liabilities:
 
 
Accounts receivable
(120)
(219)
Derivative instruments, net
(69)
47 
Other assets
54 
(111)
Accounts payable and accrued expenses
127 
(11)
Other liabilities
(54)
63 
Net cash provided by operating activities
504 
415 
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(354)
(472)
Proceeds from sale of power plants, interests and other
1,573 
0 
Purchase of Guadalupe Energy Center, net of cash
(656)
0 
(Increase) decrease in restricted cash
(15)
5 
Other
2 
(1)
Net cash provided by (used in) investing activities
550 
(468)
Cash flows from financing activities:
 
 
Borrowings under CCFC Term Loans
420 
1,197 
Repayment of CCFC Term Loans, CCFC Notes and First Lien Term Loans
(34)
(1,022)
Borrowings under Senior Unsecured Notes
2,800 
0 
Repayments of First Lien Notes
(2,800)
0 
Borrowings from project financing, notes payable and other
79 
139 
Repayments of project financing, notes payable and other
(116)
(51)
Distribution to noncontrolling interest holder
(12)
0 
Financing costs
(55)
(27)
Stock repurchases
(767)
(462)
Proceeds from exercises of stock options
19 
19 
Net cash used in financing activities
(466)
(207)
Net increase (decrease) in cash and cash equivalents
588 
(260)
Cash and cash equivalents, beginning of period
941 
1,284 
Cash and cash equivalents, end of period
1,529 
1,024 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
534 
547 
Income taxes
19 
22 
Supplemental disclosure of non-cash investing activities:
 
 
Change in capital expenditures included in accounts payable
$ 8 
$ 10 
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. Additionally, consistent with our Risk Management Policy, we enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.
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, 2013, included in our 2013 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 mark-to-market 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 — We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not have a material impact on our financial condition, results of operations or cash flows.
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, 2014 and December 31, 2013, we had cash and cash equivalents of $229 million and $292 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, 2014 and December 31, 2013 (in millions):

 
September 30, 2014
 
December 31, 2013
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
22

 
$
25

 
$
47

 
$
11

 
$
41

 
$
52

Rent reserve
4

 
—

 
4

 
3

 
—

 
3

Construction/major maintenance
69

 
12

 
81

 
35

 
20

 
55

Security/project/insurance
149

 
3

 
152

 
151

 
6

 
157

Other
—

 
2

 
2

 
3

 
2

 
5

Total
$
244

 
$
42

 
$
286

 
$
203

 
$
69

 
$
272


Property, Plant and Equipment, Net — At September 30, 2014 and December 31, 2013, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
September 30, 2014
 
December 31, 2013
 
Depreciable Lives
Buildings, machinery and equipment
$
15,528

 
$
15,838

 
3 – 47 Years
Geothermal properties
1,295

 
1,265

 
13 – 59 Years
Other
171

 
164

 
3 – 47 Years
 
16,994

 
17,267

 
 
Less: Accumulated depreciation
4,840

 
4,897

 
 
 
12,154

 
12,370

 
 
Land
109

 
103

 
 
Construction in progress
402

 
522

 
 
Property, plant and equipment, net
$
12,665

 
$
12,995

 
 
Impairment — In August 2014, we executed a term sheet with Duke Energy Florida, Inc. related to our Osprey Energy Center for a new PPA with a term of up to 27 months, after which Duke Energy Florida, Inc. would purchase our Osprey Energy Center. Although a definitive asset sale agreement is still being negotiated, and any such agreement would be subject to regulatory approval, we conducted an impairment review of our Osprey Energy Center during the third quarter of 2014. We estimated fair value of our Osprey Energy Center under a modified market approach using the discounted cash flows under the PPA and the sale proceeds to be received, which incorporated a market participant's fair value of the power plant. We recorded an impairment loss of approximately $123 million which was recorded as a separate line item on our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2014.
Capitalized Interest — The total amount of interest capitalized was $3 million and $9 million for the three months ended September 30, 2014 and 2013, respectively, and $15 million and $33 million for the nine months ended September 30, 2014 and 2013, respectively.
Treasury Stock — During the nine months ended September 30, 2014, we repurchased common stock with a value of $767 million and withheld shares with a value of $14 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees and net share employee stock option exercises under the Equity Plan.
New Accounting Standards and Disclosure Requirements
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 standard 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. We adopted Accounting Standards Update 2013-11 in the first quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.
Financial Reporting of Discontinued Operations — In April 2014, the FASB issued Accounting Standards Update 2014-08, “Presentation of Financial Statements and Property, Plant, and Equipment”. The update limits discontinued operations reporting to disposals that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The standard also requires new disclosures related to components reported as discontinued operations, as well as components of an entity that were sold and do not meet the criteria for discontinued operations reporting. The new financial statement presentation provisions relating to this standard are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard creates a five-step model for revenue recognition that requires companies to exercise judgment when considering contract terms and relevant facts and circumstances. The five-step model includes (1) identifying the contract, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations and (5) recognizing revenue when each performance obligation has been satisfied. The standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.
Going Concern — In August 2014, the FASB issued Accounting Standards Update 2014-15, “Presentation of Financial Statements — Going Concern”. This standard requires an entity’s management to assess the entity’s ability to continue as a going concern every reporting period including interim periods and requires additional disclosures if conditions or events raise substantial doubt about an entity’s ability to continue as a going concern. The standard is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
Acquisition (Notes)
Mergers, Acquisitions and Dispositions Disclosures [Text Block]
Acquisitions and Divestitures
Acquisition of Fore River Energy Center
On August 22, 2014, we, through our indirect, wholly-owned subsidiary Calpine Acquisition Company II, LLC, entered into an asset purchase agreement to purchase Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, and related plant inventory from a subsidiary of Exelon Corporation, for approximately $530 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant will increase capacity in our East segment, specifically the constrained New England market. Built in 2003, Fore River Energy Center is located in North Weymouth, Massachusetts and features two combustion turbines, two heat recovery steam generators and one steam turbine. One turbine features dual-fuel capability that will enable it to run this winter on either natural gas or fuel oil, depending on market conditions, with the other turbine scheduled to be modified to be dual-fuel capable by winter 2016. We expect the transaction to close in the fourth quarter of 2014, and expect to fund the acquisition with cash on hand or financing.
Acquisition of Guadalupe Energy Center
On February 26, 2014, we, through our indirect, wholly-owned subsidiary Calpine Guadalupe GP, LLC, completed the purchase of a power plant owned by MinnTex Power Holdings, LLC with a nameplate capacity of 1,050 MW, for approximately $625 million, excluding working capital adjustments. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment which is one of our core markets. The 110-acre site, located in Guadalupe County, Texas, which is northeast of San Antonio, Texas, includes two 525 MW generation blocks, each consisting of two GE 7FA combustion turbines, two heat recovery steam generators and one GE steam turbine. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. We funded the acquisition with $425 million in incremental CCFC Term Loans and cash on hand. See Note 4 for a further description of the incremental CCFC Term Loans. The purchase price was primarily allocated to property, plant and equipment and was finalized during the third quarter of 2014 which did not result in any material adjustments to the preliminary purchase price allocation nor the recognition of any goodwill. The pro forma incremental impact of Guadalupe Energy Center on our results of operations for each of the three and nine months ended September 30, 2014 and 2013 is not material.
Sale of Six Power Plants
On July 3, 2014, we completed the sale of six of our power plants in our East segment to NatGen Southeast Power LLC, a wholly-owned subsidiary of LS Power Equity Partners III. The purchase and sale agreement, dated April 17, 2014, stipulates the sale of 100% of the limited liability company interests in (i) Mobile Energy LLC, (ii) Santa Rosa Energy Center, LLC, (iii) Carville Energy, LLC, (iv) Decatur Energy Center, LLC, (v) Columbia Energy LLC and (vi) Calpine Oneta Power, LLC and thereby sell assets comprising 3,498 MW of combined-cycle generation capacity in Oklahoma, Louisiana, Alabama, Florida and South Carolina for a sale price of approximately $1.57 billion in cash, plus approximately $2 million for working capital and other adjustments at closing. In accordance with the purchase and sale agreement, we may also be required to make up to $16 million in future cash payments for certain planned maintenance events. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.
We recorded a gain on sale of assets, net of approximately $753 million during the three months ended September 30, 2014 and will use existing federal and state NOLs to almost entirely offset the projected taxable gains from the sale. The sale of the six power plants did not meet the criteria for treatment as discontinued operations.
The six power plants included in the transaction are as follows:
Plant Name
 
Plant Capacity
 
Location
Oneta Energy Center
 
1,134

MW
 
Coweta, OK
Carville Energy Center(1)
 
501

MW
 
St. Gabriel, LA
Decatur Energy Center
 
795

MW
 
Decatur, AL
Hog Bayou Energy Center
 
237

MW
 
Mobile, AL
Santa Rosa Energy Center
 
225

MW
 
Pace, FL
Columbia Energy Center(1)
 
606

MW
 
Calhoun County, SC
Total
 
3,498

MW
 
 
___________
(1)
Indicates combined-cycle cogeneration power plant.
Variable Interest Entities and Unconsolidated Investments in Power Plants
Variable Interest Entities and Unconsolidated Investments in Power Plants
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, 2014. See Note 5 in our 2013 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 10,365 MW and 9,427 MW at September 30, 2014 and December 31, 2013, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of $7 million and $47 million during the three and nine months ended September 30, 2014, respectively, and nil during each of the three and nine months ended September 30, 2013.
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, 2014 and December 31, 2013, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
September 30, 2014
 
September 30, 2014
 
December 31, 2013
Greenfield LP
50%
 
$
78

 
$
76

Whitby
50%
 
14

 
17

Total investments in power plants
 
 
$
92

 
$
93


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, 2014 and December 31, 2013, equity method investee debt was approximately $362 million and $395 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $181 million and $198 million at September 30, 2014 and December 31, 2013, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the three and nine months ended September 30, 2014 and 2013, is recorded in (income) from unconsolidated investments in power plants on our Consolidated Condensed Statements of Operations. 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,
 
2014
 
2013
 
2014
 
2013
Greenfield LP
$
(2
)
 
$
(5
)
 
$
(7
)
 
$
(14
)
Whitby
(3
)
 
(4
)
 
(11
)
 
(11
)
Total
$
(5
)
 
$
(9
)
 
$
(18
)
 
$
(25
)

Distributions from Greenfield LP were nil during each of the three and nine months ended September 30, 2014, and $8 million and $15 million during the three and nine months ended September 30, 2013, respectively. Distributions from Whitby were nil and $13 million during the three and nine months ended September 30, 2014, respectively, and nil and $9 million during the three and nine months ended September 30, 2013, 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, 2014 and December 31, 2013, our debt was as follows (in millions):
 
September 30, 2014

December 31, 2013
First Lien Notes
$
2,195

 
$
4,989

Senior Unsecured Notes
2,800

 
—

First Lien Term Loans
2,806

 
2,828

Project financing, notes payable and other
1,861

 
1,901

CCFC Term Loans
1,600

 
1,191

Capital lease obligations
192

 
203

Subtotal
11,454

 
11,112

Less: Current maturities
194

 
204

Total long-term debt
$
11,260

 
$
10,908


Our effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, decreased to 6.0% for the nine months ended September 30, 2014, from 6.7% for the nine months ended September 30, 2013. The issuance of our Senior Unsecured Notes in July 2014 and CCFC Term Loans, 2022 First Lien Notes, 2024 First Lien Notes and 2020 First Lien Term Loan in 2013 allowed us to reduce our overall cost of debt by replacing our CCFC Notes and a portion of our First Lien Notes with debt carrying lower interest rates.
First Lien Notes
Our First Lien Notes are summarized in the table below (in millions):
 
September 30, 2014
 
December 31, 2013
2019 First Lien Notes(1)
$
—

 
$
320

2020 First Lien Notes(1)
—

 
875

2021 First Lien Notes(1)
—

 
1,600

2022 First Lien Notes
745

 
744

2023 First Lien Notes
960

 
960

2024 First Lien Notes
490

 
490

Total First Lien Notes
$
2,195

 
$
4,989

____________
(1)
The 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes were repaid during the third quarter of 2014 with the proceeds from the issuance of our Senior Unsecured Notes, together with cash on hand, which are described in further detail below.
Senior Unsecured Notes
Our Senior Unsecured Notes are summarized in the table below (in millions):
 
September 30, 2014
 
December 31, 2013
2023 Senior Unsecured Notes
$
1,250

 
$
—

2025 Senior Unsecured Notes
1,550

 
—

Total Senior Unsecured Notes
$
2,800

 
$
—


On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. The 2023 Senior Unsecured Notes bear interest at 5.375% per annum and the 2025 Senior Unsecured Notes bear interest at 5.75% per annum, in each case payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2015. The 2023 Senior Unsecured Notes mature on January 15, 2023 and the 2025 Senior Unsecured Notes mature on January 15, 2025. Our Senior Unsecured Notes were issued at par.
Our Senior Unsecured Notes are:
•
general unsecured obligations of Calpine;
•
rank equally in right of payment with all of Calpine’s existing and future senior indebtedness;
•
effectively subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness;
•
structurally subordinated to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and
•
senior in right of payment to any of Calpine’s subordinated indebtedness.
We used the net proceeds received from the issuance of our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes, together with cash on hand, to repurchase our outstanding 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes during the third quarter of 2014. We recorded approximately $42 million in deferred financing costs and approximately $340 million in debt extinguishment costs during the third quarter of 2014 related to the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes.
First Lien Term Loans
Our First Lien Term Loans are summarized in the table below (in millions):
 
September 30, 2014
 
December 31, 2013
2018 First Lien Term Loans
$
1,601

 
$
1,614

2019 First Lien Term Loan
818

 
824

2020 First Lien Term Loan
387

 
390

Total First Lien Term Loans
$
2,806

 
$
2,828


CCFC Term Loans
In February 2014, we executed an amendment to the credit agreement associated with the CCFC Term Loans, which allowed us to issue $425 million in incremental CCFC Term Loans to fund a portion of the purchase price paid in connection with the closing of our acquisition of Guadalupe Energy Center on February 26, 2014. Guadalupe Energy Center was purchased by Calpine Guadalupe GP, LLC, a wholly-owned subsidiary of CCFC. The incremental term loans carry substantially the same terms and conditions as the $300 million in aggregate principal amount of CCFC Term Loans issued in June 2013. The incremental term loans were offered to investors at an issue price equal to 98.75% of face value.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at September 30, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
 
December 31, 2013
Corporate Revolving Facility(1)
$
206

 
$
242

CDHI(2)
199

 
218

Various project financing facilities
241

 
170

Total
$
646

 
$
630

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility. On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
(2)
During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.
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, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
 
December 31, 2013
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
2,348

 
$
2,195

 
$
5,317

 
$
4,989

Senior Unsecured Notes
2,695

 
2,800

 
—

 
—

First Lien Term Loans
2,778

 
2,806

 
2,845

 
2,828

Project financing, notes payable and other(1)
1,784

 
1,739

 
1,772

 
1,766

CCFC Term Loans
1,594

 
1,600

 
1,179

 
1,191

Total
$
11,199

 
$
11,140

 
$
11,113

 
$
10,774

____________
(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, Senior Unsecured Notes, First Lien Term Loans and CCFC Term Loans 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, 2014 and December 31, 2013, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2014
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,753

 
$
—

 
$
—

 
$
1,753

Margin deposits
177

 
—

 
—

 
177

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
649

 
—

 
—

 
649

Commodity forward contracts(2)
—

 
132

 
58

 
190

Interest rate swaps
—

 
5

 
—

 
5

Total assets
$
2,579

 
$
137

 
$
58

 
$
2,774

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
67

 
$
—

 
$
—

 
$
67

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
575

 
—

 
—

 
575

Commodity forward contracts(2)
—

 
94

 
47

 
141

Interest rate swaps
—

 
113

 
—

 
113

Total liabilities
$
642

 
$
207

 
$
47

 
$
896

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2013
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,134

 
$
—

 
$
—

 
$
1,134

Margin deposits
261

 
—

 
—

 
261

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
434

 
—

 
—

 
434

Commodity forward contracts(2)
—

 
75

 
32

 
107

Interest rate swaps
—

 
9

 
—

 
9

Total assets
$
1,829

 
$
84

 
$
32

 
$
1,945

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

 
$
—

 
$
—

 
$
5

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
495

 
—

 
—

 
495

Commodity forward contracts(2)
—

 
52

 
18

 
70

Interest rate swaps
—

 
129

 
—

 
129

Total liabilities
$
500

 
$
181

 
$
18

 
$
699

___________
(1)
As of September 30, 2014 and December 31, 2013, we had cash equivalents of $1,493 million and $889 million included in cash and cash equivalents and $260 million and $245 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
At September 30, 2014 and December 31, 2013, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor 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, 2014 and December 31, 2013:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
September 30, 2014
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(3
)
 
Discounted cash flow
 
Market price (per MWh)
 
$15.35 — $191.50/MWh
Natural Gas Contracts
 
$
10

 
Discounted cash flow
 
Market price (per MMBtu)
 
$1.98 — $22.52/MMBtu
Power Congestion Products
 
$
3

 
Discounted cash flow
 
Market price (per MWh)
 
$(19.56) — $35.30/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
7

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

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

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,
 
2014
 
2013
 
2014
 
2013
Balance, beginning of period
$
(9
)
 
$
13

 
$
14

 
$
16

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
 
Included in net income:
 
 
 
 
 
 
 
Included in operating revenues(1)
7

 
7

 
(1
)
 
8

Included in fuel and purchased energy expense(2)
5

 
1

 
9

 
—

Purchases, issuances and settlements:
 
 
 
 
 
 
 
Purchases
—

 
—

 
1

 
—

Issuances
—

 
—

 
—

 
—

Settlements
9

 
(5
)
 
(7
)
 
(8
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
Transfers into level 3(4)
—

 
—

 
—

 
—

Transfers out of level 3(5)
(1
)
 
—

 
(5
)
 
—

Balance, end of period
$
11

 
$
16

 
$
11

 
$
16

Change in unrealized gains relating to instruments still held at end of period
$
12

 
$
8

 
$
8

 
$
8

___________
(1)
For power contracts and other power-related products, 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, 2014 and 2013.
(4)
There were no transfers out of level 2 into level 3 for each of the three and nine months ended September 30, 2014 and 2013.
(5)
We had $1 million and $5 million in gains transferred out of level 3 into level 2 for the three and nine months ended September 30, 2014, respectively, primarily due to changes in market liquidity in various power markets. There were no transfers out of level 3 into level 2 for each of the three and nine months ended September 30, 2013.
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.
We also engage in limited trading activities, as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management, related to our commodity derivative portfolio which exposes us to certain market risks that are segregated from the market risks of our underlying asset portfolio. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading gains and losses were not material for the three and nine months ended September 30, 2014 and 2013.
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, 2014, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 9 years.
As of September 30, 2014 and December 31, 2013, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
September 30, 2014
 
December 31, 2013
Power (MWh)
 
(57
)
 
(29
)
Natural gas (MMBtu)
 
230

 
448

Environmental credits (Tonnes)
 
2

 
—

Interest rate swaps
 
$
1,500

 
$
1,527


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, 2014, was $15 million for which we have posted collateral of $8 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. Revenues and expenses 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. 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 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 mark-to-market 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. During the three and nine months ended September 30, 2014 and 2013, we did not have any commodity derivative instruments designated as cash flow hedges. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. 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 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.
Derivatives Included on Our Consolidated Condensed Balance Sheets
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, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
549

 
$
—

 
$
549

Long-term derivative assets
290

 
5

 
295

Total derivative assets
$
839

 
$
5

 
$
844

 
 
 
 
 
 
Current derivative liabilities
$
489

 
$
45

 
$
534

Long-term derivative liabilities
227

 
68

 
295

Total derivative liabilities
$
716

 
$
113

 
$
829

Net derivative asset (liabilities)
$
123

 
$
(108
)
 
$
15


 
December 31, 2013
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
445

 
$
—

 
$
445

Long-term derivative assets
96

 
9

 
105

Total derivative assets
$
541

 
$
9

 
$
550

 
 
 
 
 
 
Current derivative liabilities
$
404

 
$
47

 
$
451

Long-term derivative liabilities
161

 
82

 
243

Total derivative liabilities
$
565

 
$
129

 
$
694

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


 
September 30, 2014
 
December 31, 2013
 
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
$
5

 
$
108

 
$
9

 
$
115

Total derivatives designated as cash flow hedging instruments
$
5

 
$
108

 
$
9

 
$
115

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
839

 
$
716

 
$
541

 
$
565

Interest rate swaps
—

 
5

 
—

 
14

Total derivatives not designated as hedging instruments
$
839

 
$
721

 
$
541

 
$
579

Total derivatives
$
844

 
$
829

 
$
550

 
$
694


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, 2014 and December 31, 2013 (in millions):
 
 
September 30, 2014
 
 
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
 
$
649

 
$
(575
)
 
$
(74
)
 
$
—

Commodity forward contracts
 
190

 
(121
)
 
(2
)
 
67

Interest rate swaps
 
5

 
—

 
—

 
5

Total derivative assets
 
$
844

 
$
(696
)
 
$
(76
)
 
$
72

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(575
)
 
$
575

 
$
—

 
$
—

Commodity forward contracts
 
(141
)
 
121

 
8

 
(12
)
Interest rate swaps
 
(113
)
 
—

 
—

 
(113
)
Total derivative (liabilities)
 
$
(829
)
 
$
696

 
$
8

 
$
(125
)
Net derivative assets (liabilities)
 
$
15

 
$
—

 
$
(68
)
 
$
(53
)
 
 
December 31, 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
 
$
434

 
$
(420
)
 
$
(14
)
 
$
—

Commodity forward contracts
 
107

 
(60
)
 
—

 
47

Interest rate swaps
 
9

 
—

 
—

 
9

Total derivative assets
 
$
550

 
$
(480
)
 
$
(14
)
 
$
56

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

 
$
75

 
$
—

Commodity forward contracts
 
(70
)
 
60

 
1

 
(9
)
Interest rate swaps
 
(129
)
 
—

 
—

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

 
$
76

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

 
$
62

 
$
(82
)
____________
(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 and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 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 mark-to-market activity within our earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market 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,
 
2014
 
2013
 
2014
 
2013
Realized gain (loss)(1)
 
 
 
 
 
 
 
Commodity derivative instruments
$
59

 
$
27

 
$
38

 
$
60

Total realized gain (loss)
$
59

 
$
27

 
$
38

 
$
60

 
 
 
 
 
 
 
 
Mark-to-market gain (loss)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
11

 
$
43

 
$
79

 
$
15

Interest rate swaps
7

 
(5
)
 
9

 
(1
)
Total mark-to-market gain (loss)
$
18

 
$
38

 
$
88

 
$
14

Total activity, net
$
77

 
$
65

 
$
126

 
$
74

___________
(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 mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Realized and mark-to-market gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues
$
53

 
$
18

 
$
(26
)
 
$
(41
)
Derivatives contracts included in fuel and purchased energy expense
17

 
52

 
143

 
116

Interest rate swaps included in interest expense
7

 
(5
)
 
9

 
(1
)
Total activity, net
$
77

 
$
65

 
$
126

 
$
74


Derivatives Included in OCI and AOCI
We do not have any commodity derivative instruments that were designated as cash flow hedges during the three and nine months ended September 30, 2014 and 2013. 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)(3)
 
2014
 
2013
 
2014
 
2013
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
11

 
$
12

 
$
(8
)
(4) 
$
(19
)
 
Interest expense
 
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)(3)
 
2014
 
2013
 
2014
 
2013
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
2

 
$
73

 
$
(34
)
(4) 
$
(38
)
 
Interest expense
____________
(1)
We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during each of the three and nine months ended September 30, 2014 and 2013.
(2)
We recorded an income tax expense of nil and $7 million for the three months ended September 30, 2014 and 2013, respectively, and income tax expense of nil and $4 million for the nine months ended September 30, 2014 and 2013, respectively, in AOCI related to our cash flow hedging activities.
(3)
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $145 million and $148 million at September 30, 2014 and December 31, 2013, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million and $11 million at September 30, 2014 and December 31, 2013, respectively.
(4)
Includes a loss of nil and $7 million for the three months ended September 30, 2014 and 2013, respectively, and a loss of $10 million and $7 million for the nine months ended September 30, 2014 and 2013, respectively, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur.
We estimate that pre-tax net losses of $46 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, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
 
December 31, 2013
Margin deposits(1)
$
177

 
$
261

Natural gas and power prepayments
24

 
28

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
201

 
$
289

 
 
 
 
Letters of credit issued
$
444

 
$
488

First priority liens under power and natural gas agreements
12

 
31

First priority liens under interest rate swap agreements
115

 
132

Total letters of credit and first priority liens with our counterparties
$
571

 
$
651

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
67

 
$
5

Letters of credit posted with us by our counterparties
140

 
2

Total margin deposits and letters of credit posted with us by our counterparties
$
207

 
$
7

___________
(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 6 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At September 30, 2014 and December 31, 2013, $190 million and $272 million, respectively, were included in margin deposits and other prepaid expense and $11 million and $17 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,
 
2014
 
2013
 
2014
 
2013
Income tax expense
$
9

 
$
110

 
$
5

 
$
12

Effective tax rate
1
%
 
26
%
 
1
%
 
10
%

Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the impact of our NOLs, changes in unrecognized tax benefits and valuation allowances. We will use existing federal and state NOLs to almost entirely offset the projected taxable gains from the sale of six power plants in July 2014. For the three and nine months ended September 30, 2014 and 2013, our income tax expense is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs. See Note 10 in our 2013 Form 10-K for further information regarding our NOLs.   
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 were disputing with the Canadian Revenue Authority (“CRA”). We proposed a settlement of the adjusted reassessment with the CRA and the CRA 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 and did not have a material impact on our Consolidated Condensed Financial Statements.
On January 28, 2014, we received a letter from the CRA which informed us that they did not agree with our transfer price on the second issue and proposed an increase to taxable income for tax years 2006 and 2007. On June 6, 2014, we proposed a settlement, and on June 14, 2014, the CRA accepted our proposal. The adjustment to our transfer price increased taxable income for one of our Canadian affiliates and was offset by existing NOLs to which a valuation allowance had been applied. As part of the settlement, we agreed to pay some interest and withholding taxes which did not have a material impact on our Consolidated Condensed Financial Statements.
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 earnings history, we are unable to assume future profits; however, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At September 30, 2014, we had unrecognized tax benefits of $66 million. If recognized, $16 million of our unrecognized tax benefits could impact the annual effective tax rate and $50 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact on our effective tax rate. We also had accrued interest and penalties of $13 million for income tax matters at September 30, 2014. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe it is reasonably possible that a decrease within the range of nil and $11 million in unrecognized tax benefits could occur within the next 12 months primarily related to foreign tax issues.
Earnings (Loss) per Share
Earnings (Loss) per Share
Earnings 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, 2014 and 2013, are as follows (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Diluted weighted average shares calculation:
 
 
 
 
 
 
 
Weighted average shares outstanding (basic)
398,232

 
434,384

 
411,534

 
444,486

Share-based awards
4,730

 
4,109

 
4,522

 
4,060

Weighted average shares outstanding (diluted)
402,962

 
438,493

 
416,056

 
448,546


We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2014 and 2013, because they were anti-dilutive (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Share-based awards
2,854

 
5,063

 
2,855

 
5,062

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, 2014, 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. At September 30, 2014, 186,816 shares and 13,014,196 shares remain available for future issuance 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 restricted stock grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of shares of restricted stock 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 restricted stock 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 for each of the three months ended September 30, 2014 and 2013, and $25 million and $27 million for the nine months ended September 30, 2014 and 2013, 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, 2014 and 2013. At September 30, 2014, there was unrecognized compensation cost of $1 million related to options, $34 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 0.4 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 nine months ended September 30, 2014, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2013
14,114,289

 
$
18.25

 
3.1
 
$
36

Granted
—

 
$
—

 
 
 
 
Exercised
2,869,586

 
$
16.18

 
 
 
 
Forfeited
46,117

 
$
16.05

 
 
 
 
Expired
2,500

 
$
17.79

 
 
 
 
Outstanding — September 30, 2014
11,196,086

 
$
18.79

 
2.3
 
$
40

Exercisable — September 30, 2014
10,423,567

 
$
19.05

 
1.9
 
$
35

Vested and expected to vest – September 30, 2014
11,175,937

 
$
18.80

 
2.3
 
$
40


The total intrinsic value of our employee stock options exercised was $21 million for each of the nine months ended September 30, 2014 and 2013. The total cash proceeds received from our employee stock options exercised was $19 million for each of the nine months ended September 30, 2014 and 2013.
There were no stock options granted during the nine months ended September 30, 2014. The fair value of options granted during the nine months ended September 30, 2013 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
Expected term (in years)(1)
6.5

 
Risk-free interest rate(2)
1.4

%
Expected volatility(3)
25.6

%
Dividend yield(4)
—

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

 
___________
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data on the grant date 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.
A summary of our restricted stock and restricted stock unit activity for the nine months ended September 30, 2014, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2013
4,431,841

 
$
16.45

Granted
1,845,049

 
$
19.26

Forfeited
360,956

 
$
17.66

Vested
1,530,075

 
$
15.25

Nonvested — September 30, 2014
4,385,859

 
$
17.95


The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2014 and 2013, was approximately $31 million and $21 million, respectively.
Liability Classified Share-Based Awards
During the first quarter of 2014, our Board of Directors approved the award of 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, 2014 through December 31, 2016 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. Stock-based compensation expense recognized related to our liability classified share-based awards was nil for each of the three months ended September 30, 2014 and 2013 and $5 million and $1 million for the nine months ended September 30, 2014 and 2013, respectively.
A summary of our performance share unit activity for the nine months ended September 30, 2014, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2013
449,798

 
$
21.25

Granted
461,393

 
$
22.56

Forfeited
15,894

 
$
21.84

Vested(1)
15,312

 
$
21.25

Nonvested — September 30, 2014
879,985

 
$
21.93


___________
(1)
In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.
Shareholder Transaction
Shareholder Transaction
Shareholder Transaction
On July 8, 2014, we entered into a share repurchase agreement, at the prevailing market price, with a shareholder that beneficially owned slightly less than 10% of our outstanding common stock to purchase 13,213,372 shares of our common stock for the aggregate purchase price of $311,464,283 in a private transaction. We used cash on hand to fund the transaction which settled on July 10, 2014, and the repurchased shares have been returned to treasury stock.
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.
Bay Area Air Quality Management District (“BAAQMD”). On March 13, 2014, the Hearing Board of the BAAQMD entered into a stipulated conditional order for abatement agreed to by Russell City Energy Company, LLC (“RCEC”), our indirect, majority-owned subsidiary, and the BAAQMD concerning a violation of the vendor-guaranteed water droplet drift rate for RCEC’s cooling tower discovered during initial performance testing. RCEC installed additional drift eliminators and came into compliance with its water droplet drift rate on April 17, 2014. The BAAQMD reserved its rights to assert any penalty claims associated with this violation and RCEC reserved its rights to assert any defenses to such claims in future proceedings.
Segment Information
Segment 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. During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July 2014 from what was formerly our Southeast segment. Thus, beginning in the third quarter of 2014, our reportable segments are West (including geothermal), Texas and East (including North, Southeast and Canada). Our segment data below has been revised to present our segments on this revised basis for all periods.
Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. During the fourth quarter of 2013, we changed the methodology previously used during 2013 for allocating corporate expenses to our segments. This change had no impact on our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2014; however, segment amounts previously reported for the three and nine months ended September 30, 2013 were adjusted by immaterial amounts. Our segment data for the three and nine months ended September 30, 2013 have been recast to reflect these changes. The tables below show our financial data for our segments for the periods indicated (in millions).
 
Three Months Ended September 30, 2014
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
714

 
$
985

 
$
488

 
$
—

 
$
2,187

Intersegment revenues
1

 
4

 
2

 
(7
)
 
—

Total operating revenues
$
715

 
$
989

 
$
490

 
$
(7
)
 
$
2,187

Commodity Margin(1)
$
361

 
$
346

 
$
237

 
$
—

 
$
944

Add: Mark-to-market commodity activity, net and other(2)
41

 
(64
)
 
4

 
(6
)
 
(25
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
91

 
77

 
55

 
(8
)
 
215

Depreciation and amortization expense
65

 
51

 
38

 
(1
)
 
153

Sales, general and other administrative expense
11

 
18

 
8

 
—

 
37

Other operating expenses
12

 
1

 
6

 
4

 
23

Impairment losses
—

 
—

 
123

 
—

 
123

(Gain) on sale of assets, net
—

 
—

 
(753
)
 
—

 
(753
)
(Income) from unconsolidated investments in power plants
—

 
—

 
(5
)
 
—

 
(5
)
Income from operations
223

 
135

 
769

 
(1
)
 
1,126

Interest expense, net of interest income
 
 
 
 
 
 
 
 
154

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
344

Income before income taxes
 
 
 
 
 
 
 
 
$
628

 
Three Months Ended September 30, 2013
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
620

 
$
842

 
$
588

 
$
—

 
$
2,050

Intersegment revenues
1

 
(6
)
 
43

 
(38
)
 
—

Total operating revenues
$
621

 
$
836

 
$
631

 
$
(38
)
 
$
2,050

Commodity Margin(1)
$
337

 
$
328

 
$
320

 
$
—

 
$
985

Add: Mark-to-market commodity activity, net and other(2)
16

 
(5
)
 
3

 
(8
)
 
6

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
84

 
56

 
67

 
(7
)
 
200

Depreciation and amortization expense
58

 
41

 
51

 
—

 
150

Sales, general and other administrative expense
9

 
13

 
10

 
1

 
33

Other operating expenses
12

 
2

 
9

 
(3
)
 
20

(Income) from unconsolidated investments in power plants
—

 
—

 
(9
)
 
—

 
(9
)
Income from operations
190

 
211

 
195

 
1

 
597

Interest expense, net of interest income
 
 
 
 
 
 
 
 
174

Other (income) expense, net
 
 
 
 
 
 
 
 
7

Income before income taxes
 
 
 
 
 
 
 
 
$
416





 
Nine Months Ended September 30, 2014
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,692

 
$
2,592

 
$
1,807

 
$
—

 
$
6,091

Intersegment revenues
4

 
19

 
46

 
(69
)
 
—

Total operating revenues
$
1,696

 
$
2,611

 
$
1,853

 
$
(69
)
 
$
6,091

Commodity Margin(3)
$
791

 
$
644

 
$
786

 
$
—

 
$
2,221

Add: Mark-to-market commodity activity, net and other(4)
91

 
74

 
(31
)
 
(23
)
 
111

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
291

 
250

 
237

 
(24
)
 
754

Depreciation and amortization expense
183

 
141

 
129

 
—

 
453

Sales, general and other administrative expense
28

 
48

 
32

 
—

 
108

Other operating expenses
39

 
4

 
22

 
1

 
66

Impairment losses
—

 
—

 
123

 
—

 
123

(Gain) on sale of assets, net
—

 
—

 
(753
)
 
—

 
(753
)
(Income) from unconsolidated investments in power plants
—

 
—

 
(18
)
 
—

 
(18
)
Income from operations
341

 
275

 
983

 
—

 
1,599

Interest expense, net of interest income
 
 
 
 
 
 
 
 
486

 Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
361

Income before income taxes
 
 
 
 
 
 
 
 
$
752

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

 
$
1,820

 
$
1,561

 
$
—

 
$
4,863

Intersegment revenues
2

 
(24
)
 
101

 
(79
)
 
—

Total operating revenues
$
1,484

 
$
1,796

 
$
1,662

 
$
(79
)
 
$
4,863

Commodity Margin(3)
$
737

 
$
537

 
$
705

 
$
—

 
$
1,979

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

 
12

 
(24
)
 
4

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
271

 
214

 
221

 
(22
)
 
684

Depreciation and amortization expense
164

 
125

 
153

 
(1
)
 
441

Sales, general and other administrative expense
24

 
43

 
34

 
1

 
102

Other operating expenses
33

 
4

 
25

 
(4
)
 
58

(Income) from unconsolidated investments in power plants
—

 
—

 
(25
)
 
—

 
(25
)
Income from operations
243


169


309


2

 
723

Interest expense, net of interest income
 
 
 
 
 
 
 
 
517

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

Income before income taxes
 
 
 
 
 
 
 
 
$
123

_________
(1)
Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was not significant for the three months ended September 30, 2014. Commodity Margin related to these plants was $65 million for the three months ended September 30, 2013.
(2)
Includes $49 million and $44 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2014 and 2013, respectively.
(3)
Our East segment includes Commodity Margin of $81 million and $122 million for the nine months ended September 30, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014.
(4)
Includes $(7) million and $17 million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2014 and 2013, respectively.
Basis of Presentation and Summary of Significant Accounting Policies (Policies)
New Accounting Pronouncements, Policy [Policy Text Block] 
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 standard 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. We adopted Accounting Standards Update 2013-11 in the first quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.
Financial Reporting of Discontinued Operations — In April 2014, the FASB issued Accounting Standards Update 2014-08, “Presentation of Financial Statements and Property, Plant, and Equipment”. The update limits discontinued operations reporting to disposals that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The standard also requires new disclosures related to components reported as discontinued operations, as well as components of an entity that were sold and do not meet the criteria for discontinued operations reporting. The new financial statement presentation provisions relating to this standard are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard creates a five-step model for revenue recognition that requires companies to exercise judgment when considering contract terms and relevant facts and circumstances. The five-step model includes (1) identifying the contract, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations and (5) recognizing revenue when each performance obligation has been satisfied. The standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.
Going Concern — In August 2014, the FASB issued Accounting Standards Update 2014-15, “Presentation of Financial Statements — Going Concern”. This standard requires an entity’s management to assess the entity’s ability to continue as a going concern every reporting period including interim periods and requires additional disclosures if conditions or events raise substantial doubt about an entity’s ability to continue as a going concern. The standard is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
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, 2013, included in our 2013 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 mark-to-market 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 — We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not have a material impact on our financial condition, results of operations or cash flows.
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, 2014 and December 31, 2013, we had cash and cash equivalents of $229 million and $292 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.
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. Revenues and expenses 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. 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 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 mark-to-market 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. During the three and nine months ended September 30, 2014 and 2013, we did not have any commodity derivative instruments designated as cash flow hedges. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. 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 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.
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 Components of Restricted Cash 
The table below represents the components of our restricted cash as of September 30, 2014 and December 31, 2013 (in millions):

 
September 30, 2014
 
December 31, 2013
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
22

 
$
25

 
$
47

 
$
11

 
$
41

 
$
52

Rent reserve
4

 
—

 
4

 
3

 
—

 
3

Construction/major maintenance
69

 
12

 
81

 
35

 
20

 
55

Security/project/insurance
149

 
3

 
152

 
151

 
6

 
157

Other
—

 
2

 
2

 
3

 
2

 
5

Total
$
244

 
$
42

 
$
286

 
$
203

 
$
69

 
$
272

Schedule of Property, Plant and Equipment 
Property, Plant and Equipment, Net — At September 30, 2014 and December 31, 2013, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
September 30, 2014
 
December 31, 2013
 
Depreciable Lives
Buildings, machinery and equipment
$
15,528

 
$
15,838

 
3 – 47 Years
Geothermal properties
1,295

 
1,265

 
13 – 59 Years
Other
171

 
164

 
3 – 47 Years
 
16,994

 
17,267

 
 
Less: Accumulated depreciation
4,840

 
4,897

 
 
 
12,154

 
12,370

 
 
Land
109

 
103

 
 
Construction in progress
402

 
522

 
 
Property, plant and equipment, net
$
12,665

 
$
12,995

 
 
Acquisition (Tables)
Six Power Plants To be disposed of [Table Text Block]
The six power plants included in the transaction are as follows:
Plant Name
 
Plant Capacity
 
Location
Oneta Energy Center
 
1,134

MW
 
Coweta, OK
Carville Energy Center(1)
 
501

MW
 
St. Gabriel, LA
Decatur Energy Center
 
795

MW
 
Decatur, AL
Hog Bayou Energy Center
 
237

MW
 
Mobile, AL
Santa Rosa Energy Center
 
225

MW
 
Pace, FL
Columbia Energy Center(1)
 
606

MW
 
Calhoun County, SC
Total
 
3,498

MW
 
 
___________
(1)
Indicates combined-cycle cogeneration power plant.
Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables)
Income (Loss) 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,
 
2014
 
2013
 
2014
 
2013
Greenfield LP
$
(2
)
 
$
(5
)
 
$
(7
)
 
$
(14
)
Whitby
(3
)
 
(4
)
 
(11
)
 
(11
)
Total
$
(5
)
 
$
(9
)
 
$
(18
)
 
$
(25
)

Schedule of Equity Method Investments 
At September 30, 2014 and December 31, 2013, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
September 30, 2014
 
September 30, 2014
 
December 31, 2013
Greenfield LP
50%
 
$
78

 
$
76

Whitby
50%
 
14

 
17

Total investments in power plants
 
 
$
92

 
$
93

Debt (Tables)
Schedule of Long-term Debt Instruments 
At September 30, 2014 and December 31, 2013, our debt was as follows (in millions):
 
September 30, 2014

December 31, 2013
First Lien Notes
$
2,195

 
$
4,989

Senior Unsecured Notes
2,800

 
—

First Lien Term Loans
2,806

 
2,828

Project financing, notes payable and other
1,861

 
1,901

CCFC Term Loans
1,600

 
1,191

Capital lease obligations
192

 
203

Subtotal
11,454

 
11,112

Less: Current maturities
194

 
204

Total long-term debt
$
11,260

 
$
10,908

First Lien Notes 
Our First Lien Notes are summarized in the table below (in millions):
 
September 30, 2014
 
December 31, 2013
2019 First Lien Notes(1)
$
—

 
$
320

2020 First Lien Notes(1)
—

 
875

2021 First Lien Notes(1)
—

 
1,600

2022 First Lien Notes
745

 
744

2023 First Lien Notes
960

 
960

2024 First Lien Notes
490

 
490

Total First Lien Notes
$
2,195

 
$
4,989

____________
(1)
The 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes were repaid during the third quarter of 2014 with the proceeds from the issuance of our Senior Unsecured Notes, together with cash on hand, which are described in further detail below.
Senior Unsecured Notes 
Our Senior Unsecured Notes are summarized in the table below (in millions):
 
September 30, 2014
 
December 31, 2013
2023 Senior Unsecured Notes
$
1,250

 
$
—

2025 Senior Unsecured Notes
1,550

 
—

Total Senior Unsecured Notes
$
2,800

 
$
—

First Lien Term Loans 
Our First Lien Term Loans are summarized in the table below (in millions):
 
September 30, 2014
 
December 31, 2013
2018 First Lien Term Loans
$
1,601

 
$
1,614

2019 First Lien Term Loan
818

 
824

2020 First Lien Term Loan
387

 
390

Total First Lien Term Loans
$
2,806

 
$
2,828

Schedule of Line of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at September 30, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
 
December 31, 2013
Corporate Revolving Facility(1)
$
206

 
$
242

CDHI(2)
199

 
218

Various project financing facilities
241

 
170

Total
$
646

 
$
630

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility. On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
(2)
During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.
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, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
 
December 31, 2013
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
2,348

 
$
2,195

 
$
5,317

 
$
4,989

Senior Unsecured Notes
2,695

 
2,800

 
—

 
—

First Lien Term Loans
2,778

 
2,806

 
2,845

 
2,828

Project financing, notes payable and other(1)
1,784

 
1,739

 
1,772

 
1,766

CCFC Term Loans
1,594

 
1,600

 
1,179

 
1,191

Total
$
11,199

 
$
11,140

 
$
11,113

 
$
10,774

____________
(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 
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2014
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,753

 
$
—

 
$
—

 
$
1,753

Margin deposits
177

 
—

 
—

 
177

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
649

 
—

 
—

 
649

Commodity forward contracts(2)
—

 
132

 
58

 
190

Interest rate swaps
—

 
5

 
—

 
5

Total assets
$
2,579

 
$
137

 
$
58

 
$
2,774

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
67

 
$
—

 
$
—

 
$
67

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
575

 
—

 
—

 
575

Commodity forward contracts(2)
—

 
94

 
47

 
141

Interest rate swaps
—

 
113

 
—

 
113

Total liabilities
$
642

 
$
207

 
$
47

 
$
896

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2013
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,134

 
$
—

 
$
—

 
$
1,134

Margin deposits
261

 
—

 
—

 
261

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
434

 
—

 
—

 
434

Commodity forward contracts(2)
—

 
75

 
32

 
107

Interest rate swaps
—

 
9

 
—

 
9

Total assets
$
1,829

 
$
84

 
$
32

 
$
1,945

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

 
$
—

 
$
—

 
$
5

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
495

 
—

 
—

 
495

Commodity forward contracts(2)
—

 
52

 
18

 
70

Interest rate swaps
—

 
129

 
—

 
129

Total liabilities
$
500

 
$
181

 
$
18

 
$
699

___________
(1)
As of September 30, 2014 and December 31, 2013, we had cash equivalents of $1,493 million and $889 million included in cash and cash equivalents and $260 million and $245 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
Fair Value Inputs, Assets, Quantitative Information 
The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at September 30, 2014 and December 31, 2013:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
September 30, 2014
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(3
)
 
Discounted cash flow
 
Market price (per MWh)
 
$15.35 — $191.50/MWh
Natural Gas Contracts
 
$
10

 
Discounted cash flow
 
Market price (per MMBtu)
 
$1.98 — $22.52/MMBtu
Power Congestion Products
 
$
3

 
Discounted cash flow
 
Market price (per MWh)
 
$(19.56) — $35.30/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
7

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

 
Discounted cash flow
 
Market price (per MWh)
 
$(8.79) — $11.53/MWh
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,
 
2014
 
2013
 
2014
 
2013
Balance, beginning of period
$
(9
)
 
$
13

 
$
14

 
$
16

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
 
Included in net income:
 
 
 
 
 
 
 
Included in operating revenues(1)
7

 
7

 
(1
)
 
8

Included in fuel and purchased energy expense(2)
5

 
1

 
9

 
—

Purchases, issuances and settlements:
 
 
 
 
 
 
 
Purchases
—

 
—

 
1

 
—

Issuances
—

 
—

 
—

 
—

Settlements
9

 
(5
)
 
(7
)
 
(8
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
Transfers into level 3(4)
—

 
—

 
—

 
—

Transfers out of level 3(5)
(1
)
 
—

 
(5
)
 
—

Balance, end of period
$
11

 
$
16

 
$
11

 
$
16

Change in unrealized gains relating to instruments still held at end of period
$
12

 
$
8

 
$
8

 
$
8

___________
(1)
For power contracts and other power-related products, 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, 2014 and 2013.
(4)
There were no transfers out of level 2 into level 3 for each of the three and nine months ended September 30, 2014 and 2013.
(5)
We had $1 million and $5 million in gains transferred out of level 3 into level 2 for the three and nine months ended September 30, 2014, respectively, primarily due to changes in market liquidity in various power markets. There were no transfers out of level 3 into level 2 for each of the three and nine months ended September 30, 2013.
Derivative Instruments (Tables)
Schedule of Notional Amounts of Outstanding Derivative Positions 
As of September 30, 2014 and December 31, 2013, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
September 30, 2014
 
December 31, 2013
Power (MWh)
 
(57
)
 
(29
)
Natural gas (MMBtu)
 
230

 
448

Environmental credits (Tonnes)
 
2

 
—

Interest rate swaps
 
$
1,500

 
$
1,527

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, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
549

 
$
—

 
$
549

Long-term derivative assets
290

 
5

 
295

Total derivative assets
$
839

 
$
5

 
$
844

 
 
 
 
 
 
Current derivative liabilities
$
489

 
$
45

 
$
534

Long-term derivative liabilities
227

 
68

 
295

Total derivative liabilities
$
716

 
$
113

 
$
829

Net derivative asset (liabilities)
$
123

 
$
(108
)
 
$
15


 
December 31, 2013
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
445

 
$
—

 
$
445

Long-term derivative assets
96

 
9

 
105

Total derivative assets
$
541

 
$
9

 
$
550

 
 
 
 
 
 
Current derivative liabilities
$
404

 
$
47

 
$
451

Long-term derivative liabilities
161

 
82

 
243

Total derivative liabilities
$
565

 
$
129

 
$
694

Net derivative asset (liabilities)
$
(24
)
 
$
(120
)
 
$
(144
)
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value 
 
September 30, 2014
 
December 31, 2013
 
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
$
5

 
$
108

 
$
9

 
$
115

Total derivatives designated as cash flow hedging instruments
$
5

 
$
108

 
$
9

 
$
115

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
839

 
$
716

 
$
541

 
$
565

Interest rate swaps
—

 
5

 
—

 
14

Total derivatives not designated as hedging instruments
$
839

 
$
721

 
$
541

 
$
579

Total derivatives
$
844

 
$
829

 
$
550

 
$
694

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, 2014 and December 31, 2013 (in millions):
 
 
September 30, 2014
 
 
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
 
$
649

 
$
(575
)
 
$
(74
)
 
$
—

Commodity forward contracts
 
190

 
(121
)
 
(2
)
 
67

Interest rate swaps
 
5

 
—

 
—

 
5

Total derivative assets
 
$
844

 
$
(696
)
 
$
(76
)
 
$
72

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(575
)
 
$
575

 
$
—

 
$
—

Commodity forward contracts
 
(141
)
 
121

 
8

 
(12
)
Interest rate swaps
 
(113
)
 
—

 
—

 
(113
)
Total derivative (liabilities)
 
$
(829
)
 
$
696

 
$
8

 
$
(125
)
Net derivative assets (liabilities)
 
$
15

 
$
—

 
$
(68
)
 
$
(53
)
 
 
December 31, 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
 
$
434

 
$
(420
)
 
$
(14
)
 
$
—

Commodity forward contracts
 
107

 
(60
)
 
—

 
47

Interest rate swaps
 
9

 
—

 
—

 
9

Total derivative assets
 
$
550

 
$
(480
)
 
$
(14
)
 
$
56

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

 
$
75

 
$
—

Commodity forward contracts
 
(70
)
 
60

 
1

 
(9
)
Interest rate swaps
 
(129
)
 
—

 
—

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

 
$
76

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

 
$
62

 
$
(82
)
____________
(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 and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral.
Realized Unrealized Gain Loss by Instrument 
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market 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,
 
2014
 
2013
 
2014
 
2013
Realized gain (loss)(1)
 
 
 
 
 
 
 
Commodity derivative instruments
$
59

 
$
27

 
$
38

 
$
60

Total realized gain (loss)
$
59

 
$
27

 
$
38

 
$
60

 
 
 
 
 
 
 
 
Mark-to-market gain (loss)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
11

 
$
43

 
$
79

 
$
15

Interest rate swaps
7

 
(5
)
 
9

 
(1
)
Total mark-to-market gain (loss)
$
18

 
$
38

 
$
88

 
$
14

Total activity, net
$
77

 
$
65

 
$
126

 
$
74

___________
(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 mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
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,
 
2014
 
2013
 
2014
 
2013
Realized and mark-to-market gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues
$
53

 
$
18

 
$
(26
)
 
$
(41
)
Derivatives contracts included in fuel and purchased energy expense
17

 
52

 
143

 
116

Interest rate swaps included in interest expense
7

 
(5
)
 
9

 
(1
)
Total activity, net
$
77

 
$
65

 
$
126

 
$
74

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)(3)
 
2014
 
2013
 
2014
 
2013
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
11

 
$
12

 
$
(8
)
(4) 
$
(19
)
 
Interest expense
 
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)(3)
 
2014
 
2013
 
2014
 
2013
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
2

 
$
73

 
$
(34
)
(4) 
$
(38
)
 
Interest expense
____________
(1)
We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during each of the three and nine months ended September 30, 2014 and 2013.
(2)
We recorded an income tax expense of nil and $7 million for the three months ended September 30, 2014 and 2013, respectively, and income tax expense of nil and $4 million for the nine months ended September 30, 2014 and 2013, respectively, in AOCI related to our cash flow hedging activities.
(3)
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $145 million and $148 million at September 30, 2014 and December 31, 2013, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million and $11 million at September 30, 2014 and December 31, 2013, respectively.
(4)
Includes a loss of nil and $7 million for the three months ended September 30, 2014 and 2013, respectively, and a loss of $10 million and $7 million for the nine months ended September 30, 2014 and 2013, respectively, that was reclassified from AOCI to interest expense, 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, 2014 and December 31, 2013 (in millions):
 
September 30, 2014
 
December 31, 2013
Margin deposits(1)
$
177

 
$
261

Natural gas and power prepayments
24

 
28

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
201

 
$
289

 
 
 
 
Letters of credit issued
$
444

 
$
488

First priority liens under power and natural gas agreements
12

 
31

First priority liens under interest rate swap agreements
115

 
132

Total letters of credit and first priority liens with our counterparties
$
571

 
$
651

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
67

 
$
5

Letters of credit posted with us by our counterparties
140

 
2

Total margin deposits and letters of credit posted with us by our counterparties
$
207

 
$
7

___________
(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 6 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At September 30, 2014 and December 31, 2013, $190 million and $272 million, respectively, were included in margin deposits and other prepaid expense and $11 million and $17 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,
 
2014
 
2013
 
2014
 
2013
Income tax expense
$
9

 
$
110

 
$
5

 
$
12

Effective tax rate
1
%
 
26
%
 
1
%
 
10
%
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, 2014 and 2013, are as follows (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Diluted weighted average shares calculation:
 
 
 
 
 
 
 
Weighted average shares outstanding (basic)
398,232

 
434,384

 
411,534

 
444,486

Share-based awards
4,730

 
4,109

 
4,522

 
4,060

Weighted average shares outstanding (diluted)
402,962

 
438,493

 
416,056

 
448,546

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, 2014 and 2013, because they were anti-dilutive (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2014
 
2013
 
2014
 
2013
Share-based awards
2,854

 
5,063

 
2,855

 
5,062

Stock-Based Compensation (Tables)
Schedule of Share-based Compensation, Activity [Table Text Block] 
A summary of our performance share unit activity for the nine months ended September 30, 2014, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2013
449,798

 
$
21.25

Granted
461,393

 
$
22.56

Forfeited
15,894

 
$
21.84

Vested(1)
15,312

 
$
21.25

Nonvested — September 30, 2014
879,985

 
$
21.93


___________
(1)
In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.
Schedule of Non-Qualified Stock Option Activity 
A summary of all of our non-qualified stock option activity for the nine months ended September 30, 2014, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2013
14,114,289

 
$
18.25

 
3.1
 
$
36

Granted
—

 
$
—

 
 
 
 
Exercised
2,869,586

 
$
16.18

 
 
 
 
Forfeited
46,117

 
$
16.05

 
 
 
 
Expired
2,500

 
$
17.79

 
 
 
 
Outstanding — September 30, 2014
11,196,086

 
$
18.79

 
2.3
 
$
40

Exercisable — September 30, 2014
10,423,567

 
$
19.05

 
1.9
 
$
35

Vested and expected to vest – September 30, 2014
11,175,937

 
$
18.80

 
2.3
 
$
40

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
Expected term (in years)(1)
6.5

 
Risk-free interest rate(2)
1.4

%
Expected volatility(3)
25.6

%
Dividend yield(4)
—

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

 
___________
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data on the grant date 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 nine months ended September 30, 2014, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2013
4,431,841

 
$
16.45

Granted
1,845,049

 
$
19.26

Forfeited
360,956

 
$
17.66

Vested
1,530,075

 
$
15.25

Nonvested — September 30, 2014
4,385,859

 
$
17.95

Segment 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, 2014
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
714

 
$
985

 
$
488

 
$
—

 
$
2,187

Intersegment revenues
1

 
4

 
2

 
(7
)
 
—

Total operating revenues
$
715

 
$
989

 
$
490

 
$
(7
)
 
$
2,187

Commodity Margin(1)
$
361

 
$
346

 
$
237

 
$
—

 
$
944

Add: Mark-to-market commodity activity, net and other(2)
41

 
(64
)
 
4

 
(6
)
 
(25
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
91

 
77

 
55

 
(8
)
 
215

Depreciation and amortization expense
65

 
51

 
38

 
(1
)
 
153

Sales, general and other administrative expense
11

 
18

 
8

 
—

 
37

Other operating expenses
12

 
1

 
6

 
4

 
23

Impairment losses
—

 
—

 
123

 
—

 
123

(Gain) on sale of assets, net
—

 
—

 
(753
)
 
—

 
(753
)
(Income) from unconsolidated investments in power plants
—

 
—

 
(5
)
 
—

 
(5
)
Income from operations
223

 
135

 
769

 
(1
)
 
1,126

Interest expense, net of interest income
 
 
 
 
 
 
 
 
154

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
344

Income before income taxes
 
 
 
 
 
 
 
 
$
628

 
Three Months Ended September 30, 2013
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
620

 
$
842

 
$
588

 
$
—

 
$
2,050

Intersegment revenues
1

 
(6
)
 
43

 
(38
)
 
—

Total operating revenues
$
621

 
$
836

 
$
631

 
$
(38
)
 
$
2,050

Commodity Margin(1)
$
337

 
$
328

 
$
320

 
$
—

 
$
985

Add: Mark-to-market commodity activity, net and other(2)
16

 
(5
)
 
3

 
(8
)
 
6

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
84

 
56

 
67

 
(7
)
 
200

Depreciation and amortization expense
58

 
41

 
51

 
—

 
150

Sales, general and other administrative expense
9

 
13

 
10

 
1

 
33

Other operating expenses
12

 
2

 
9

 
(3
)
 
20

(Income) from unconsolidated investments in power plants
—

 
—

 
(9
)
 
—

 
(9
)
Income from operations
190

 
211

 
195

 
1

 
597

Interest expense, net of interest income
 
 
 
 
 
 
 
 
174

Other (income) expense, net
 
 
 
 
 
 
 
 
7

Income before income taxes
 
 
 
 
 
 
 
 
$
416





 
Nine Months Ended September 30, 2014
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,692

 
$
2,592

 
$
1,807

 
$
—

 
$
6,091

Intersegment revenues
4

 
19

 
46

 
(69
)
 
—

Total operating revenues
$
1,696

 
$
2,611

 
$
1,853

 
$
(69
)
 
$
6,091

Commodity Margin(3)
$
791

 
$
644

 
$
786

 
$
—

 
$
2,221

Add: Mark-to-market commodity activity, net and other(4)
91

 
74

 
(31
)
 
(23
)
 
111

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
291

 
250

 
237

 
(24
)
 
754

Depreciation and amortization expense
183

 
141

 
129

 
—

 
453

Sales, general and other administrative expense
28

 
48

 
32

 
—

 
108

Other operating expenses
39

 
4

 
22

 
1

 
66

Impairment losses
—

 
—

 
123

 
—

 
123

(Gain) on sale of assets, net
—

 
—

 
(753
)
 
—

 
(753
)
(Income) from unconsolidated investments in power plants
—

 
—

 
(18
)
 
—

 
(18
)
Income from operations
341

 
275

 
983

 
—

 
1,599

Interest expense, net of interest income
 
 
 
 
 
 
 
 
486

 Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
361

Income before income taxes
 
 
 
 
 
 
 
 
$
752

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

 
$
1,820

 
$
1,561

 
$
—

 
$
4,863

Intersegment revenues
2

 
(24
)
 
101

 
(79
)
 
—

Total operating revenues
$
1,484

 
$
1,796

 
$
1,662

 
$
(79
)
 
$
4,863

Commodity Margin(3)
$
737

 
$
537

 
$
705

 
$
—

 
$
1,979

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

 
12

 
(24
)
 
4

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
271

 
214

 
221

 
(22
)
 
684

Depreciation and amortization expense
164

 
125

 
153

 
(1
)
 
441

Sales, general and other administrative expense
24

 
43

 
34

 
1

 
102

Other operating expenses
33

 
4

 
25

 
(4
)
 
58

(Income) from unconsolidated investments in power plants
—

 
—

 
(25
)
 
—

 
(25
)
Income from operations
243


169


309


2

 
723

Interest expense, net of interest income
 
 
 
 
 
 
 
 
517

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

Income before income taxes
 
 
 
 
 
 
 
 
$
123

_________
(1)
Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was not significant for the three months ended September 30, 2014. Commodity Margin related to these plants was $65 million for the three months ended September 30, 2013.
(2)
Includes $49 million and $44 million of lease levelization and $4 million and $4 million of amortization expense for the three months ended September 30, 2014 and 2013, respectively.
(3)
Our East segment includes Commodity Margin of $81 million and $122 million for the nine months ended September 30, 2014 and 2013, respectively, related to the six power plants in our East segment that were sold in July 2014.
(4)
Includes $(7) million and $17 million of lease levelization and $11 million and $11 million of amortization expense for the nine months ended September 30, 2014 and 2013, 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, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Accounting Policies [Line Items]
 
 
 
 
 
Current
$ 244 
 
$ 244 
 
$ 203 
Non-current
42 
 
42 
 
69 
Total
286 
 
286 
 
272 
Cash and cash equivalents subject to project finance facilities and lease agreements
229 
 
229 
 
292 
Interest Costs Capitalized
3 
9 
15 
33 
 
Treasury Stock, Value, Acquired, Cost Method
 
 
767 
 
 
Adjustments Related to Tax Withholding for Share-based Compensation
 
 
14 
 
 
Debt Service
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
22 
 
22 
 
11 
Non-current
25 
 
25 
 
41 
Total
47 
 
47 
 
52 
Rent Reserve
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
4 
 
4 
 
3 
Non-current
0 
 
0 
 
0 
Total
4 
 
4 
 
3 
Construction Major Maintenance
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
69 
 
69 
 
35 
Non-current
12 
 
12 
 
20 
Total
81 
 
81 
 
55 
Security Project Insurance
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
149 
 
149 
 
151 
Non-current
3 
 
3 
 
6 
Total
152 
 
152 
 
157 
Other
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
0 
 
0 
 
3 
Non-current
2 
 
2 
 
2 
Total
$ 2 
 
$ 2 
 
$ 5 
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 
 
 
Basis of Presentation and Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 27 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Dec. 31, 2016
Subsequent Event [Member]
Property, Plant and Equipment [Line Items]
 
 
 
 
 
 
Power Plant Agreement Term
 
 
 
 
 
0 years 27 months 
Impairment losses
$ 123 
$ 0 
$ 123 
$ 0 
 
 
Interest Costs Capitalized
3 
9 
15 
33 
 
 
Buildings, machinery and equipment
15,528 
 
15,528 
 
15,838 
 
Geothermal properties
1,295 
 
1,295 
 
1,265 
 
Other
171 
 
171 
 
164 
 
Property, Plant and Equipment, Gross
16,994 
 
16,994 
 
17,267 
 
Less: Accumulated depreciation
4,840 
 
4,840 
 
4,897 
 
Property, Plant and Equipment, Gross, Less Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
12,154 
 
12,154 
 
12,370 
 
Land
109 
 
109 
 
103 
 
Construction in progress
402 
 
402 
 
522 
 
Property, plant and equipment, net
$ 12,665 
 
$ 12,665 
 
$ 12,995 
 
Acquisition (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
MW
Sep. 30, 2013
Sep. 30, 2014
MW
Sep. 30, 2013
Dec. 31, 2013
MW
Business Acquisition [Line Items]
 
 
 
 
 
Number of power plants to be disposed of
6 
 
 
 
 
Ownership percentage before divestiture of business
100.00% 
 
100.00% 
 
 
Working Capital Adjustment to Sale price
$ 2,000,000 
 
 
 
 
Business Combination, Contingent Consideration, Liability
16,000,000 
 
16,000,000 
 
 
Gain (Loss) on Disposition of Assets
753,000,000 
0 
753,000,000 
0 
 
Power generation capacity
10,365 
 
10,365 
 
9,427 
Fore River Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
809 
 
809 
 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net
530,000,000 
 
530,000,000 
 
 
Guadalupe Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
1,050 
 
1,050 
 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net
625,000,000 
 
625,000,000 
 
 
Guadalupe Expansion Capacity [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
400 
 
400 
 
 
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net
15,000,000 
 
15,000,000 
 
 
Incremental CCFC Term Loans [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Debt Instrument, Face Amount
425,000,000 
 
425,000,000 
 
 
Oneta Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
1,134 
 
1,134 
 
 
Carville Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
501 1
 
501 1
 
 
Decatur Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
795 
 
795 
 
 
Hog Bayou Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
237 
 
237 
 
 
Santa Rosa Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
225 
 
225 
 
 
Columbia Energy Center [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Power generation capacity
606 1
 
606 1
 
 
Six Power Plants [Member]
 
 
 
 
 
Business Acquisition [Line Items]
 
 
 
 
 
Proceeds from Sale of Productive Assets
$ 1,570,000,000 
 
 
 
 
Power generation capacity
3,498 
 
3,498 
 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 92 
$ 93 
Greenfield [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
78 
76 
Equity Method Investment, Ownership Percentage
50.00% 
 
Whitby [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 14 
$ 17 
Equity Method Investment, Ownership Percentage
50.00% 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Income from Unconsolidated Investements 10-Q) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
(Income) from unconsolidated investments in power plants
$ (5)
$ (9)
$ (18)
$ (25)
Greenfield [Member]
 
 
 
 
(Income) from unconsolidated investments in power plants
(2)
(5)
(7)
(14)
Whitby [Member]
 
 
 
 
(Income) from unconsolidated investments in power plants
$ (3)
$ (4)
$ (11)
$ (11)
Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
MW
Sep. 30, 2013
Sep. 30, 2014
MW
Sep. 30, 2013
Dec. 31, 2013
MW
Variable Interest Entity [Line Items]
 
 
 
 
 
Power generation capacity
10,365 
 
10,365 
 
9,427 
Variable Interest Entity, Financial or Other Support, Amount
$ 7 
$ 0 
$ 47 
$ 0 
 
Equity Method Investment, Summarized Financial Information, Debt
362 
 
362 
 
395 
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt
181 
 
181 
 
198 
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
0 
8 
0 
15 
 
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 
$ 13 
$ 9 
 
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, 2014
Dec. 31, 2013
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
$ 11,454 
$ 11,112 
Debt, Current
194 
204 
Long-term Debt, Excluding Current Maturities
11,260 
10,908 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,195 
4,989 
Unsecured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,800 
0 
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,806 
2,828 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,861 
1,901 
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,600 
1,191 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 192 
$ 203 
Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
First Lien Notes 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 0 1
$ 320 1
First Lien Notes 2020 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 1
875 1
First Lien Notes 2021 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
0 1
1,600 1
2022 First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
745 
744 
First Lien Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
960 
960 
2024 First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
490 
490 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 2,195 
$ 4,989 
Debt (First Lien Term Loans) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
First Lien Term Loans 2018 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 1,601 
$ 1,614 
First Lien Term Loan 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
818 
824 
2020 First Lien Term Loan [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
387 
390 
First Lien Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 2,806 
$ 2,828 
Debt (Letter of Credit) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 646 
$ 630 
Corporate Revolving Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
206 1
242 1
CDH [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
199 2
218 2
Various Project Financing Facilities [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 241 
$ 170 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
$ 2,348 
$ 5,317 
Senior Unsecured Notes, Fair Value Disclosure
2,695 
0 
Loans Payable, Fair Value Disclosure
2,778 
2,845 
Notes Payable, Other Payables, Disclosure
1,784 1
1,772 1
Subsidiaries Term Loan
1,594 
1,179 
Debt Excluding Capital Leases
11,199 
11,113 
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Notes Payable, Fair Value Disclosure
2,195 
4,989 
Senior Unsecured Notes, Fair Value Disclosure
2,800 
0 
Loans Payable, Fair Value Disclosure
2,806 
2,828 
Notes Payable, Other Payables, Disclosure
1,739 1
1,766 1
Subsidiaries Term Loan
1,600 
1,191 
Debt Excluding Capital Leases
$ 11,140 
$ 10,774 
Debt (Debt Textuals) (Details) (USD $)
3 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
 
 
 
Line of Credit Facility, Increase (Decrease), Net
 
 
$ 500,000,000 
Debt Instrument, Interest Rate, Effective Percentage
6.00% 
6.70% 
 
Line of Credit Facility, Maximum Borrowing Capacity
 
 
$ 1,500,000,000 
Debt CCFC Term Loans (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Jun. 30, 2013
CCFC Term Loan B-2 [Member]
Sep. 30, 2014
Incremental CCFC Term Loans [Member]
Debt Instrument [Line Items]
 
 
Debt Instrument, Face Amount
$ 300 
$ 425 
Long Term Debt net of Original Issuance Disount
 
98.75% 
Debt Senior Unsecured Notes (Details) (USD $)
3 Months Ended 9 Months Ended 3 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Senior Unsecured Notes 2023 [Member]
Dec. 31, 2013
Senior Unsecured Notes 2023 [Member]
Sep. 30, 2014
Senior Unsecured Notes 2025 [Member]
Dec. 31, 2013
Senior Unsecured Notes 2025 [Member]
Sep. 30, 2014
Unsecured Debt [Member]
Dec. 31, 2013
Unsecured Debt [Member]
Sep. 30, 2014
2019, 2020 and 2021 First Lien Notes [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
$ 1,250,000,000 
 
$ 1,550,000,000 
 
 
 
 
Long-term Debt
 
 
 
 
1,250,000,000 
0 
1,550,000,000 
0 
2,800,000,000 
0 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
5.375% 
 
5.75% 
 
 
 
 
Deferred Finance Costs, Net
 
 
 
 
 
 
 
 
 
 
42,000,000 
Debt Extinguishment costs
$ 340,000,000 
$ 0 
$ 341,000,000 
$ 68,000,000 
 
 
 
 
 
 
$ 340,000,000 
Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 1,753 1
$ 1,134 1
Margin deposits
177 2
261 2
Commodity futures contracts
649 
434 
Commodity forward contracts
190 3
107 3
Interest Rate Swap Assets, Fair Value Disclosure
5 
9 
Total assets
2,774 
1,945 
Margin deposits held by us posted by our counterparties
67 2 4
5 2 4
Commodity futures contracts
575 
495 
Commodity forward contracts
141 3
70 3
Interest rate swaps
113 
129 
Liabilities, Fair Value Disclosure
896 
699 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1,753 1
1,134 1
Margin deposits
177 
261 
Commodity futures contracts
649 
434 
Commodity forward contracts
0 3
0 3
Interest Rate Swap Assets, Fair Value Disclosure
0 
0 
Total assets
2,579 
1,829 
Margin deposits held by us posted by our counterparties
67 
5 
Commodity futures contracts
575 
495 
Commodity forward contracts
0 3
0 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
642 
500 
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
132 3
75 3
Interest Rate Swap Assets, Fair Value Disclosure
5 
9 
Total assets
137 
84 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
94 3
52 3
Interest rate swaps
113 
129 
Liabilities, Fair Value Disclosure
207 
181 
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
58 3
32 3
Interest Rate Swap Assets, Fair Value Disclosure
0 
0 
Total assets
58 
32 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
47 3
18 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
$ 47 
$ 18 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Balance, beginning of period
$ (9)
$ 13 
$ 14 
$ 16 
 
Included in net income:
 
 
 
 
 
Included in operating revenues
7 1
7 1
(1)1
8 1
 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense
5 2
1 2
9 2
0 2
 
Purchases, issuances and settlements:
 
 
 
 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases
0 
0 
1 
0 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances
0 
0 
0 
0 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements
9 
(5)
(7)
(8)
 
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
(1)3 5
0 3 5
(5)3 5
0 3 5
 
Balance, end of period
11 
16 
11 
16 
 
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)
12 
8 
8 
8 
 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
 
 
Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure
1,493 
 
1,493 
 
889 
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure
$ 260 
 
$ 260 
 
$ 245 
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) (USD $)
Sep. 30, 2014
Dec. 31, 2013
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
$ 15,000,000 
$ (144,000,000)
Power Contracts [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
(3,000,000)
7,000,000 
Power Contracts [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
15.35 
28.92 
Power Contracts [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
191.50 
53.15 
Natural Gas [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
10,000,000 
0 
Natural Gas [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
1.98 
0 
Natural Gas [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
22.52 
0 
Power Congestion Products [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
3,000,000 
7,000,000 
Power Congestion Products [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
(19.56)
(8.79)
Power Congestion Products [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
$ 35.30 
$ 11.53 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2014
MWh
Dec. 31, 2013
MWh
Power [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Nonmonetary Notional Amount, Energy Measure
(57)
(29)
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Nonmonetary Notional Amount, Energy Measure
230 
448 
Environmental Credits [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Nonmonetary Notional Amount, Mass
2 
0 
Interest Rate Swap [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Notional Amount
$ 1,500 
$ 1,527 
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
$ 549 
$ 445 
Long-term derivative assets
295 
105 
Total derivative assets
844 
550 
Derivative liabilities, current
534 
451 
Long-term derivative liabilities
295 
243 
Total derivative liabilities
829 
694 
Derivative, Fair Value, Net
15 
(144)
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
5 
9 
Total derivative liabilities
108 
115 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
839 
541 
Total derivative liabilities
721 
579 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
0 
0 
Derivative Assets, Noncurrent
5 
9 
Total derivative assets
5 
9 
Current derivative liabilities
45 
47 
Derivative Liabilities, Noncurrent
68 
82 
Total derivative liabilities
113 
129 
Derivative, Fair Value, Net
(108)
(120)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
5 
9 
Total derivative liabilities
108 
115 
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
0 
0 
Total derivative liabilities
5 
14 
Energy Related Derivative [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
549 
445 
Derivative Assets, Noncurrent
290 
96 
Total derivative assets
839 
541 
Current derivative liabilities
489 
404 
Derivative Liabilities, Noncurrent
227 
161 
Total derivative liabilities
716 
565 
Derivative, Fair Value, Net
123 
(24)
Energy Related Derivative [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
839 
541 
Total derivative liabilities
$ 716 
$ 565 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Power contracts included in operating revenues
$ 2,187 
$ 2,050 
$ 6,091 
$ 4,863 
Natural gas contracts included in fuel and purchased energy expense
1,268 
1,059 
3,759 
2,880 
Interest expense
156 
176 
491 
522 
Gain (Loss) on Derivative Instruments, Net, Pretax
77 
65 
126 
74 
Gain (Loss) on Sale of Derivatives
59 1
27 1
38 1
60 1
Mark-to-market gain (loss)
18 2
38 2
88 2
14 2
Power [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Power contracts included in operating revenues
53 
18 
(26)
(41)
Interest Rate Swap [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Interest expense
7 
(5)
9 
(1)
Mark-to-market gain (loss)
7 2
(5)2
9 2
(1)2
Energy Related Derivative [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Gain (Loss) on Sale of Derivatives
59 1
27 1
38 1
60 1
Mark-to-market gain (loss)
11 2
43 2
79 2
15 2
Natural Gas [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Natural gas contracts included in fuel and purchased energy expense
$ 17 
$ 52 
$ 143 
$ 116 
Derivative Instruments (Details 4) (Details) (Interest Rate Swap [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Interest Rate Swap [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
$ 11 1 2
$ 12 1 2
$ 2 1 2
$ 73 1 2
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
$ (8)1 2 3 4
$ (19)1 2 3
$ (34)1 2 3 4
$ (38)1 2 3
Derivative Instruments (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Parent [Member]
Dec. 31, 2013
Parent [Member]
Sep. 30, 2014
Noncontrolling Interest [Member]
Dec. 31, 2013
Noncontrolling Interest [Member]
Derivatives, Fair Value [Line Items]
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax
$ 0 
$ 7 
$ 0 
$ 4 
 
 
 
 
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax
 
 
 
 
145 
148 
12 
11 
Derivative Instruments (Textuals) [Abstract]
 
 
 
 
 
 
 
 
Maximum length of time hedging using interest rate derivative instruments
 
 
9 years 
 
 
 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
15 
 
15 
 
 
 
 
 
Collateral Already Posted, Aggregate Fair Value
8 
 
8 
 
 
 
 
 
Additional Collateral, Aggregate Fair Value
0 
 
0 
 
 
 
 
 
(Gain) Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net
0 
7 
10 
7 
 
 
 
 
Cash Flow Hedge (Gain) Loss to be Reclassified within Twelve Months
 
 
$ 46 
 
 
 
 
 
Derivative Instruments (Detail 5) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 844 
$ 550 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(696)
(480)
Derivative, Collateral, Obligation to Return Cash
(76)1
(14)1
Derivative Liability, Fair Value, Gross Liability
(829)
(694)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
696 
480 
Derivative, Collateral, Right to Reclaim Cash
8 1
76 1
Derivative, Fair Value, Net
15 
(144)
Derivative Fair Value, Amount Not Offset Against Collateral, Net
0 
0 
Margin/Cash (Received) Posted Subject to Master Netting Arrangement
(68)1
62 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
72 
56 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(125)
(138)
Derivative, Fair Value, Amount Offset Against Collateral, Net
(53)
(82)
Commodity Exchange Traded Futures and Swaps Contracts [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
649 
434 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(575)
(420)
Derivative, Collateral, Obligation to Return Cash
(74)1
(14)1
Derivative Liability, Fair Value, Gross Liability
(575)
(495)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
575 
420 
Derivative, Collateral, Right to Reclaim Cash
0 1
75 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
0 
0 
Derivative Liability, Fair Value, Amount Offset Against Collateral
0 
0 
Commodity Forward Contract [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
190 
107 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(121)
(60)
Derivative, Collateral, Obligation to Return Cash
(2)1
0 1
Derivative Liability, Fair Value, Gross Liability
(141)
(70)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
121 
60 
Derivative, Collateral, Right to Reclaim Cash
8 1
1 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
67 
47 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(12)
(9)
Interest Rate Swap [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
5 
9 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
0 
0 
Derivative, Collateral, Obligation to Return Cash
0 1
0 1
Derivative Liability, Fair Value, Gross Liability
(113)
(129)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
0 
0 
Derivative, Collateral, Right to Reclaim Cash
0 1
0 1
Derivative, Fair Value, Net
(108)
(120)
Derivative Asset, Fair Value, Amount Offset Against Collateral
5 
9 
Derivative Liability, Fair Value, Amount Offset Against Collateral
$ (113)
$ (129)
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Use of Collateral [Abstract]
 
 
Margin deposits
$ 177 1
$ 261 1
Natural gas and power prepayments
24 
28 
Total margin deposits and natural gas and power prepayments with our counterparties
201 2
289 2
Letters of credit issued
444 
488 
First priority liens under power and natural gas agreements
12 
31 
First priority liens under interest rate swap agreements
115 
132 
Total letters of credit and first priority liens with our counterparties
571 
651 
Margin deposits held by us posted by our counterparties
67 1 3
5 1 3
Letters of credit posted with us by our counterparties
140 
2 
Total margin deposits and letters of credit posted with us by our counterparties
207 
7 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
11 
17 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
$ 190 
$ 272 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Income Tax Contingency [Line Items]
 
 
 
 
Income tax (expense) benefit
$ (9,000,000)
$ (110,000,000)
$ (5,000,000)
$ (12,000,000)
Effective Income Tax Rate, Continuing Operations
1.00% 
26.00% 
1.00% 
10.00% 
Unrecognized Tax Benefits
66,000,000 
 
66,000,000 
 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
16,000,000 
 
16,000,000 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
13,000,000 
 
13,000,000 
 
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound
0 
 
0 
 
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound
11,000,000 
 
11,000,000 
 
Unrecognized Tax Benefit Related to Deferred Tax Asset
$ 50,000,000 
 
$ 50,000,000 
 
Earnings (Loss) per Share (Details)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Earnings (Loss) per Share [Abstract]
 
 
 
 
Share-based awards
2,854 
5,063 
2,855 
5,062 
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, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Reconciliation of Basic to Diluted Weighted Average Shares [Abstract]
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
398,232 
434,384 
411,534 
444,486 
Weighted Average Number Diluted Shares Outstanding Adjustment
4,730 
4,109 
4,522 
4,060 
Weighted average shares of common stock outstanding (in thousands)
402,962 
438,493 
416,056 
448,546 
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, 2014
Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
 
 
Options, Outstanding
11,196,086 
14,114,289 
Options, Outstanding, Weighted Average Exercise Price
$ 18.79 
$ 18.25 
Options, Outstanding, Weighted Average Remaining Contractual Term
2 years 3 months 10 days 
3 years 1 month 6 days 
Options, Outstanding, Intrinsic Value
$ 40 
$ 36 
Options, Grants in Period, Gross
0 
 
Options, Grants in Period, Weighted Average Exercise Price
$ 0.00 
 
Options, Exercises in Period
2,869,586 
 
Options, Exercises in Period, Weighted Average Exercise Price
$ 16.18 
 
Options, Forfeitures in Period
46,117 
 
Options, Forfeitures in Period, Weighted Average Exercise Price
$ 16.05 
 
Options, Expirations in Period
2,500 
 
Options, Expirations in Period, Weighted Average Exercise Price
$ 17.79 
 
Options, Exercisable
10,423,567 
 
Options, Exercisable, Weighted Average Exercise Price
$ 19.05 
 
Options, Exercisable, Weighted Average Remaining Contractual Term
1 year 10 months 25 days 
 
Options, Exercisable, Intrinsic Value
35 
 
Options, Vested and Expected to Vest, Outstanding
11,175,937 
 
Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price
$ 18.80 
 
Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term
2 years 3 months 10 days 
 
Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value
$ 40 
 
Stock-Based Compensation (Asummptions used to estimate fair value for options) (Details)
9 Months Ended
Sep. 30, 2013
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
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
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 5.31 
Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) (Restricted Stock [Member], USD $)
9 Months Ended
Sep. 30, 2014
Dec. 31, 2013
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
4,385,859 
4,431,841 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 17.95 
$ 16.45 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
1,845,049 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 19.26 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
360,956 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value
$ 17.66 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
1,530,075 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 15.25 
 
Stock-Based Compensation (Stock Based Compensation Textuals) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Minimum [Member]
Sep. 30, 2014
Maximum [Member]
Sep. 30, 2014
Stock Options [Member]
Sep. 30, 2014
Restricted Stock [Member]
Sep. 30, 2013
Restricted Stock [Member]
Dec. 31, 2013
Restricted Stock [Member]
Sep. 30, 2014
Restricted Stock Units (RSUs) [Member]
Sep. 30, 2014
Performance Shares [Member]
Dec. 31, 2013
Performance Shares [Member]
Sep. 30, 2014
Director Plan [Member]
Sep. 30, 2014
Equity Plan [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
 
 
 
 
 
 
 
4,385,859 
 
4,431,841 
 
879,985 
449,798 
 
 
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 
5 years 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Minimum Range
 
 
 
 
5 years 
10 years 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized
 
 
 
 
 
 
 
 
 
 
 
 
 
567,000 
40,533,000 
Common Stock, Capital Shares Reserved for Future Issuance
 
 
 
 
 
 
 
 
 
 
 
 
 
186,816 
13,014,196 
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 
$ 8 
$ 25 
$ 27 
 
 
 
 
 
 
 
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
 
 
 
 
 
 
1 
34 
 
 
0 
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
 
 
 
 
 
 
4 months 26 days 
1 year 3 months 10 days 
 
 
7 months 7 days 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value
 
 
21 
21 
 
 
 
 
 
 
 
 
 
 
 
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options
 
 
19 
19 
 
 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
 
 
 
 
 
 
 
31 
21 
 
 
 
 
 
 
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards
$ 0 
$ 0 
$ 5 
$ 1 
 
 
 
 
 
 
 
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
 
 
 
 
 
 
 
1,845,049 
 
 
 
461,393 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
 
 
 
 
 
 
 
$ 19.26 
 
 
 
$ 22.56 
 
 
 
Stock-Based Compensation Liability Based Stock Compensation (Details) (Performance Shares [Member], USD $)
9 Months Ended
Sep. 30, 2014
Dec. 31, 2013
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, Nonvested, Weighted Average Grant Date Fair Value
$ 21.93 
$ 21.25 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
461,393 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 22.56 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
15,894 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value
$ 21.84 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
15,312 1
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 21.25 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number
879,985 
449,798 
Shareholder Transaction (Details) (USD $)
Sep. 30, 2014
Shareholder Transaction [Abstract]
 
Shareholder Ownership Percentage
10.00% 
Common Stock Purchased from Shareholder
13,213,372 
Purchase Price of Common Stock Purchased from Shareholder
$ 311,464,283 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
$ 2,187 
$ 2,050 
$ 6,091 
$ 4,863 
Commodity Margin
944 1
985 1
2,221 1
1,979 1
Add: Mark-to-market commodity activity, net and other
(25)2
6 2
111 2
4 2
Plant operating expense
215 
200 
754 
684 
Depreciation and amortization expense
153 
150 
453 
441 
Sales, general and other administrative expense
37 
33 
108 
102 
Other operating expenses
23 
20 
66 
58 
Impairment losses
123 
0 
123 
0 
(Gain) on sale of assets, net
(753)
0 
(753)
0 
(Income) loss from unconsolidated investments in power plants
(5)
(9)
(18)
(25)
Income from operations
1,126 
597 
1,599 
723 
Interest expense, net of interest income
154 
174 
486 
517 
Debt extinguishment costs and other (income) expense, net
344 
7 
361 
83 
Income before income taxes
628 
416 
752 
123 
Commodity Margin for Six Southeast Power Plants Sold
 
65 
81 
122 
Lease levelization
49 
44 
(7)
17 
Contract amortization
4 
4 
11 
11 
West [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
715 
621 
1,696 
1,484 
Commodity Margin
361 1
337 1
791 1
737 1
Add: Mark-to-market commodity activity, net and other
41 2
16 2
91 2
(2)2
Plant operating expense
91 
84 
291 
271 
Depreciation and amortization expense
65 
58 
183 
164 
Sales, general and other administrative expense
11 
9 
28 
24 
Other operating expenses
12 
12 
39 
33 
Impairment losses
0 
 
0 
 
(Gain) on sale of assets, net
0 
 
0 
 
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Income from operations
223 
190 
341 
243 
Texas [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
989 
836 
2,611 
1,796 
Commodity Margin
346 1
328 1
644 1
537 1
Add: Mark-to-market commodity activity, net and other
(64)2
(5)2
74 2
18 2
Plant operating expense
77 
56 
250 
214 
Depreciation and amortization expense
51 
41 
141 
125 
Sales, general and other administrative expense
18 
13 
48 
43 
Other operating expenses
1 
2 
4 
4 
Impairment losses
0 
 
0 
 
(Gain) on sale of assets, net
0 
 
0 
 
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Income from operations
135 
211 
275 
169 
East [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
490 
631 
1,853 
1,662 
Commodity Margin
237 1
320 1
786 1
705 1
Add: Mark-to-market commodity activity, net and other
4 2
3 2
(31)2
12 2
Plant operating expense
55 
67 
237 
221 
Depreciation and amortization expense
38 
51 
129 
153 
Sales, general and other administrative expense
8 
10 
32 
34 
Other operating expenses
6 
9 
22 
25 
Impairment losses
123 
 
123 
 
(Gain) on sale of assets, net
(753)
 
(753)
 
(Income) loss from unconsolidated investments in power plants
(5)
(9)
(18)
(25)
Income from operations
769 
195 
983 
309 
Geography Consolidation and Elimination [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
(7)
(38)
(69)
(79)
Commodity Margin
0 1
0 1
0 1
0 1
Add: Mark-to-market commodity activity, net and other
(6)2
(8)2
(23)2
(24)2
Plant operating expense
(8)
(7)
(24)
(22)
Depreciation and amortization expense
(1)
0 
0 
(1)
Sales, general and other administrative expense
0 
1 
0 
1 
Other operating expenses
4 
(3)
1 
(4)
Impairment losses
0 
 
0 
 
(Gain) on sale of assets, net
0 
 
0 
 
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Income from operations
(1)
1 
0 
2 
Operating Segments [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
2,187 
2,050 
6,091 
4,863 
Operating Segments [Member] |
West [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
714 
620 
1,692 
1,482 
Operating Segments [Member] |
Texas [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
985 
842 
2,592 
1,820 
Operating Segments [Member] |
East [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
488 
588 
1,807 
1,561 
Operating Segments [Member] |
Geography Consolidation and Elimination [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
0 
0 
0 
0 
Intersegment Eliminations [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
0 
0 
0 
0 
Intersegment Eliminations [Member] |
West [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
1 
1 
4 
2 
Intersegment Eliminations [Member] |
Texas [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
4 
(6)
19 
(24)
Intersegment Eliminations [Member] |
East [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
2 
43 
46 
101 
Intersegment Eliminations [Member] |
Geography Consolidation and Elimination [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
$ (7)
$ (38)
$ (69)
$ (79)