CALPINE CORP, 10-Q filed on 5/1/2015
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2015
Apr. 29, 2015
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
Mar. 31, 2015 
 
Document Fiscal Year Focus
2015 
 
Document Fiscal Period Focus
Q1 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
372,345,009 
Consolidated Condensed Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Operating revenues:
 
 
Commodity revenue
$ 1,638 
$ 2,048 
Mark-to-market gain (loss)
3 
(86)
Other revenue
5 
3 
Operating revenues
1,646 
1,965 
Operating expenses:
 
 
Commodity expense
1,077 
1,370 
Mark-to-market (gain)
(67)
(13)
Fuel and purchased energy expense
1,010 
1,357 
Plant operating expense
260 
265 
Depreciation and amortization expense
158 
153 
Sales, general and other administrative expense
37 
33 
Other operating expenses
20 
22 
Total operating expenses
1,485 
1,830 
(Income) from unconsolidated investments in power plants
(5)
(9)
Income from operations
166 
144 
Interest expense
154 
166 
Interest (income)
(1)
(1)
Debt extinguishment costs
19 
1 
Other (income) expense, net
2 
10 
Loss before income taxes
(8)
(32)
Income tax benefit
(1)
(19)
Net income (loss)
(7)
(13)
Net income attributable to the noncontrolling interest
(3)
(4)
Net loss attributable to Calpine
$ (10)
$ (17)
Basic and diluted loss per common share attributable to Calpine:
 
 
Weighted Average Number of Shares Outstanding, Basic and Diluted
372,935 
420,105 
Earnings Per Share, Basic and Diluted
$ (0.03)
$ (0.04)
Consolidated Condensed Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
 
 
Net loss
$ (7)
$ (13)
Cash flow hedging activities:
 
 
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss
(18)
(13)
Reclassification adjustment for loss on cash flow hedges realized in net loss
12 
13 
Foreign currency translation loss
(12)
(6)
Income tax expense
0 
0 
Other comprehensive loss
(18)
(6)
Comprehensive loss
(25)
(19)
Comprehensive (income) attributable to the noncontrolling interest
(2)
(4)
Comprehensive loss attributable to Calpine
$ (27)
$ (23)
Consolidated Condensed Balance Sheets (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Current assets:
 
 
Cash and cash equivalents ($296 and $229 attributable to VIEs)
$ 796 
$ 717 
Accounts receivable, net of allowance of $5 and $4
503 
648 
Inventories
486 
447 
Margin deposits and other prepaid expense
150 
148 
Restricted cash, current ($99 and $106 attributable to VIEs)
162 
195 
Derivative assets, current
1,858 
2,058 
Other current assets
17 
7 
Total current assets
3,972 
4,220 
Property, plant and equipment, net ($4,300 and $4,342 attributable to VIEs)
13,178 
13,190 
Restricted cash, net of current portion ($46 and $48 attributable to VIEs)
47 
49 
Investments in power plants
88 
95 
Long-term derivative assets
711 
439 
Other assets ($161 and $164 attributable to VIEs)
386 
385 
Total assets
18,382 
18,378 
Current liabilities:
 
 
Accounts payable
456 
580 
Accrued interest payable
163 
165 
Debt, current portion ($146 and $150 attributable to VIEs)
197 
199 
Derivative liabilities, current
1,643 
1,782 
Other current liabilities
385 
473 
Total current liabilities
2,844 
3,199 
Debt, net of current portion ($3,199 and $3,242 attributable to VIEs)
11,520 
11,083 
Long-term derivative liabilities
572 
444 
Other long-term liabilities
241 
221 
Total liabilities
15,177 
14,947 
Commitments and contingencies (see Note 10)
   
   
Stockholders’ equity:
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding
0 
0 
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 504,015,575 and 502,287,022 shares issued, respectively, and 373,837,359 and 381,921,264 shares outstanding, respectively
1 
1 
Treasury stock, at cost, 130,178,216 and 120,365,758 shares, respectively
(2,557)
(2,345)
Additional paid-in capital
12,453 
12,440 
Accumulated deficit
(6,550)
(6,540)
Accumulated other comprehensive loss
(195)
(178)
Total Calpine stockholders’ equity
3,152 
3,378 
Noncontrolling interest
53 
53 
Total stockholders’ equity
3,205 
3,431 
Total liabilities and stockholders’ equity
$ 18,382 
$ 18,378 
Consolidated Condensed Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Cash and cash equivalents ($296 and $229 attributable to VIEs)
$ 796 
$ 717 
Accounts receivable, net of allowance of $5 and $4
5 
4 
Restricted cash, current ($99 and $106 attributable to VIEs)
162 
195 
Property, plant and equipment, net ($4,300 and $4,342 attributable to VIEs)
13,178 
13,190 
Restricted cash, net of current portion ($46 and $48 attributable to VIEs)
47 
49 
Other assets ($161 and $164 attributable to VIEs)
386 
385 
Debt, current portion ($146 and $150 attributable to VIEs)
197 
199 
Debt, net of current portion ($3,199 and $3,242 attributable to VIEs)
11,520 
11,083 
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
504,015,575 
502,287,022 
Common Stock, Shares, Outstanding
373,837,359 
381,921,264 
Treasury Stock, Shares
130,178,216 
120,365,758 
Variable Interest Entity, Primary Beneficiary [Member]
 
 
Cash and cash equivalents ($296 and $229 attributable to VIEs)
296 
229 
Restricted cash, current ($99 and $106 attributable to VIEs)
99 
106 
Property, plant and equipment, net ($4,300 and $4,342 attributable to VIEs)
4,300 
4,342 
Restricted cash, net of current portion ($46 and $48 attributable to VIEs)
46 
48 
Other assets ($161 and $164 attributable to VIEs)
161 
164 
Debt, current portion ($146 and $150 attributable to VIEs)
146 
150 
Debt, net of current portion ($3,199 and $3,242 attributable to VIEs)
$ 3,199 
$ 3,242 
Consolidated Condensed Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Cash flows from operating activities:
 
 
Net loss
$ (7)
$ (13)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
Depreciation and amortization expense(1)
171 1
164 1
Deferred income taxes
0 
(13)
Mark-to-market activity, net
(71)2
72 2
(Income) from unconsolidated investments in power plants
(5)
(9)
Return on unconsolidated investments in power plants
0 
13 
Stock-based compensation expense
11 
10 
Other
(2)
(2)
Change in operating assets and liabilities:
 
 
Accounts receivable
120 
(75)
Derivative instruments, net
(17)
(87)
Other assets
(28)
29 
Accounts payable and accrued expenses
(204)
106 
Other liabilities
15 
(72)
Net cash provided by (used in) operating activities
(17)
123 
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(162)
(119)
Purchase of Guadalupe Energy Center, net of cash
0 
(656)
Decrease in restricted cash
35 
6 
Other
(1)
0 
Net cash used in investing activities
(128)
(769)
Cash flows from financing activities:
 
 
Borrowings under CCFC Term Loans
0 
420 
Repayment of CCFC Term Loans and First Lien Term Loans
(11)
(11)
Borrowings under Senior Unsecured Notes
650 
0 
Repurchase of First Lien Notes
(147)
0 
Repayments of project financing, notes payable and other
(58)
(43)
Financing costs
(11)
(10)
Stock repurchases
(202)
(140)
Proceeds from exercises of stock options
3 
4 
Net cash provided by financing activities
224 
220 
Net increase (decrease) in cash and cash equivalents
79 
(426)
Cash and cash equivalents, beginning of period
717 
941 
Cash and cash equivalents, end of period
796 
515 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
146 
225 
Income taxes
6 
8 
Supplemental disclosure of non-cash investing activities:
 
 
Change in capital expenditures included in accounts payable
$ (22)
$ (9)
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 (included in our West segment), Texas (included in our Texas segment) and the Northeast region (included in our East segment) 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, power and other 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, 2014, included in our 2014 Form 10-K. The results for interim periods are not 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.
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 are expected to 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 March 31, 2015 and December 31, 2014 (in millions):

 
March 31, 2015
 
December 31, 2014
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
12

 
$
24

 
$
36

 
$
10

 
$
25

 
$
35

Rent reserve
2

 
—

 
2

 
4

 
—

 
4

Construction/major maintenance
60

 
17

 
77

 
54

 
17

 
71

Security/project/insurance
88

 
4

 
92

 
127

 
5

 
132

Other
—

 
2

 
2

 
—

 
2

 
2

Total
$
162

 
$
47

 
$
209

 
$
195

 
$
49

 
$
244


Property, Plant and Equipment, Net — At March 31, 2015 and December 31, 2014, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2015
 
December 31, 2014
 
Depreciable Lives
Buildings, machinery and equipment
$
16,092

 
$
16,059

 
3 – 47 Years
Geothermal properties
1,314

 
1,294

 
13 – 59 Years
Other
205

 
203

 
3 – 47 Years
 
17,611

 
17,556

 
 
Less: Accumulated depreciation
5,122

 
4,984

 
 
 
12,489

 
12,572

 
 
Land
119

 
120

 
 
Construction in progress
570

 
498

 
 
Property, plant and equipment, net
$
13,178

 
$
13,190

 
 
Capitalized Interest — The total amount of interest capitalized was $5 million and $6 million for the three months ended March 31, 2015 and 2014, respectively.
Treasury Stock — During the three months ended March 31, 2015, we repurchased a total of 9.3 million shares of our outstanding common stock for approximately $202 million at an average price of $21.57 per share. Additionally, we withheld shares with a value of $10 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees under the Equity Plan.
Acquisition of Fore River Energy Center — During the three months ended March 31, 2015, there were no material adjustments made to the initial purchase price allocation recorded in the fourth quarter of 2014 related to our acquisition of Fore River Energy Center. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation nor do we expect to recognize any goodwill as a result of this acquisition.
New Accounting Standards and Disclosure Requirements
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.

Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” This standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidated analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard is effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have but do not anticipate a material impact on our financial condition, results of operations or cash flows.

Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and requires retrospective adoption 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.

Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods and allows for either prospective or retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.
Variable Interest Entities and Unconsolidated Investments in Power Plants
Variable Interest Entities and Unconsolidated Investments in Power Plants
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the three months ended March 31, 2015. See Note 5 in our 2014 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 at both March 31, 2015 and December 31, 2014. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil and $40 million during the three months ended March 31, 2015 and 2014, respectively.
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 March 31, 2015 and December 31, 2014, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
March 31, 2015
 
March 31, 2015
 
December 31, 2014
Greenfield LP
50%
 
$
69

 
$
78

Whitby
50%
 
19

 
17

Total investments in power plants
 
 
$
88

 
$
95


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 March 31, 2015 and December 31, 2014, equity method investee debt was approximately $310 million and $342 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $155 million and $171 million at March 31, 2015 and December 31, 2014, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the three months ended March 31, 2015 and 2014, 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 March 31,
 
 
2015
 
2014
Greenfield LP
 
$
(2
)
 
$
(5
)
Whitby
 
(3
)
 
(4
)
Total
 
$
(5
)
 
$
(9
)

Distributions from Greenfield LP were nil during each of the three months ended March 31, 2015, and 2014. Distributions from Whitby were nil and $13 million during the three months ended March 31, 2015 and 2014, 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.
Significant Unconsolidated Subsidiary — Whitby met the criteria of a significant unconsolidated subsidiary for the three months ended March 31, 2015, based upon the relationship of our equity income from our investment to our consolidated net loss before taxes. The summarized financial data for Whitby for the three months ended March 31, 2015 and 2014, are set forth below (in millions):
Whitby
Condensed Statements of Operations
(Unaudited)

 
Three Months Ended March 31,
 
2015
 
2014
Revenues
$
15

 
$
15

Operating expenses
9

 
7

Net income
$
6

 
$
8

Debt
Debt
Debt
Our debt at March 31, 2015 and December 31, 2014, was as follows (in millions):
 
March 31, 2015

December 31, 2014
Senior Unsecured Notes
$
3,450

 
$
2,800

First Lien Term Loans
2,792

 
2,799

First Lien Notes
1,928

 
2,075

Project financing, notes payable and other
1,762

 
1,810

CCFC Term Loans
1,592

 
1,596

Capital lease obligations
193

 
202

Subtotal
11,717

 
11,282

Less: Current maturities
197

 
199

Total long-term debt
$
11,520

 
$
11,083


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 5.5% for the three months ended March 31, 2015, from 6.2% for the same period in 2014. The issuance of our Senior Unsecured Notes in July 2014 and February 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with unsecured debt carrying lower interest rates.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
March 31, 2015
 
December 31, 2014
2023 Senior Unsecured Notes
$
1,250

 
$
1,250

2024 Senior Unsecured Notes
650

 
—

2025 Senior Unsecured Notes
1,550

 
1,550

Total Senior Unsecured Notes
$
3,450

 
$
2,800


In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5% per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on February 1, 2024 and contain substantially similar covenants, qualifications, exceptions and limitations as our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes. We used the net proceeds received from the issuance of our 2024 Senior Unsecured Notes to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. During the first quarter of 2015, we recorded approximately $9 million in deferred financing costs related to the issuance of our 2024 Senior Unsecured Notes and approximately $19 million in debt extinguishment costs related to the partial repurchase of our 2023 First Lien Notes.
First Lien Term Loans
The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2015
 
December 31, 2014
2018 First Lien Term Loans
$
1,593

 
$
1,597

2019 First Lien Term Loan
814

 
816

2020 First Lien Term Loan
385

 
386

Total First Lien Term Loans
$
2,792

 
$
2,799


First Lien Notes
The amounts outstanding under our First Lien Notes are summarized in the table below (in millions):
 
March 31, 2015
 
December 31, 2014
2022 First Lien Notes
$
745

 
$
745

2023 First Lien Notes(1)
693

 
840

2024 First Lien Notes
490

 
490

Total First Lien Notes
$
1,928

 
$
2,075

____________
(1)
On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, which is described in further detail above.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
 
December 31, 2014
Corporate Revolving Facility(1)
$
202

 
$
223

CDHI
235

 
214

Various project financing facilities
186

 
207

Total
$
623

 
$
644

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
 
December 31, 2014
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
Senior Unsecured Notes
$
3,462

 
$
3,450

 
$
2,832

 
$
2,800

First Lien Term Loans
2,795

 
2,792

 
2,769

 
2,799

First Lien Notes
2,091

 
1,928

 
2,247

 
2,075

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

 
1,655

 
1,734

 
1,688

CCFC Term Loans
1,580

 
1,592

 
1,540

 
1,596

Total
$
11,619

 
$
11,417

 
$
11,122

 
$
10,958

____________
(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 Senior Unsecured Notes, First Lien Term Loans, First Lien Notes 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 March 31, 2015 and December 31, 2014, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2015
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
965

 
$
—

 
$
—

 
$
965

Margin deposits
107

 
—

 
—

 
107

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
2,037

 
—

 
—

 
2,037

Commodity forward contracts(2)
—

 
295

 
233

 
528

Interest rate swaps
—

 
4

 
—

 
4

Total assets
$
3,109

 
$
299

 
$
233

 
$
3,641

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
40

 
$
—

 
$
—

 
$
40

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,814

 
—

 
—

 
1,814

Commodity forward contracts(2)
—

 
253

 
30

 
283

Interest rate swaps
—

 
118

 
—

 
118

Total liabilities
$
1,854

 
$
371

 
$
30

 
$
2,255

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2014
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
896

 
$
—

 
$
—

 
$
896

Margin deposits
96

 
—

 
—

 
96

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
2,134

 
—

 
—

 
2,134

Commodity forward contracts(2)
—

 
195

 
164

 
359

Interest rate swaps
—

 
4

 
—

 
4

Total assets
$
3,126

 
$
199

 
$
164

 
$
3,489

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
47

 
$
—

 
$
—

 
$
47

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,870

 
—

 
—

 
1,870

Commodity forward contracts(2)
—

 
163

 
79

 
242

Interest rate swaps
—

 
114

 
—

 
114

Total liabilities
$
1,917

 
$
277

 
$
79

 
$
2,273

___________
(1)
As of March 31, 2015 and December 31, 2014, we had cash equivalents of $757 million and $679 million included in cash and cash equivalents and $208 million and $217 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
At March 31, 2015 and December 31, 2014, 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. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2015 and December 31, 2014:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
March 31, 2015
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
201

 
Discounted cash flow
 
Market price (per MWh)
 
$13.43 — $123.25/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
74

 
Discounted cash flow
 
Market price (per MWh)
 
$14.00 — $122.79/MWh
Natural Gas Contracts
 
$
5

 
Discounted cash flow
 
Market price (per MMBtu)
 
$1.00 — $10.86/MMBtu
Power Congestion Products
 
$
9

 
Discounted cash flow
 
Market price (per MWh)
 
$(19.56) — $19.56/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 March 31,
 
 
2015
 
2014
Balance, beginning of period
 
$
85

 
$
14

Realized and mark-to-market gains (losses):
 
 
 
 
Included in net loss:
 
 
 
 
Included in operating revenues(1)
 
131

 
(10
)
Included in fuel and purchased energy expense(2)
 
3

 
5

Purchases and settlements:
 
 
 
 
Purchases
 
2

 
1

Settlements
 
(10
)
 
(3
)
Transfers in and/or out of level 3(3):
 
 
 
 
Transfers into level 3(4)
 
(1
)
 
—

Transfers out of level 3(5)
 
(7
)
 
1

Balance, end of period
 
$
203

 
$
8

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
134

 
$
(5
)
___________
(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 months ended March 31, 2015 and 2014.
(4)
We had $(1) million in losses transferred out of level 2 into level 3 for the three months ended March 31, 2015. There were no transfers out of level 2 into level 3 for the three months ended March 31, 2014.
(5)
We had $(7) million in gains and $1 million in losses transferred out of level 3 into level 2 for the three months ended March 31, 2015 and 2014, respectively, due to changes in market liquidity in various power markets.
Derivative Instruments
Derivative Instruments
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
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 months ended March 31, 2015 and 2014.
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 March 31, 2015, 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 March 31, 2015 and December 31, 2014, 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
 
March 31, 2015
 
December 31, 2014
Power (MWh)
 
(79
)
 
(62
)
Natural gas (MMBtu)
 
693

 
291

Environmental credits (Tonnes)
 
1

 
—

Interest rate swaps
 
$
1,419

 
$
1,431


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 March 31, 2015, was $16 million for which we have posted collateral of $10 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $8 million would be required and that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated 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 months ended March 31, 2015 and 2014, 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 Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product 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 March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,858

 
$
—

 
$
1,858

Long-term derivative assets
707

 
4

 
711

Total derivative assets
$
2,565

 
$
4

 
$
2,569

 
 
 
 
 
 
Current derivative liabilities
$
1,600

 
$
43

 
$
1,643

Long-term derivative liabilities
497

 
75

 
572

Total derivative liabilities
$
2,097

 
$
118

 
$
2,215

Net derivative asset (liabilities)
$
468

 
$
(114
)
 
$
354


 
December 31, 2014
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
2,058

 
$
—

 
$
2,058

Long-term derivative assets
435

 
4

 
439

Total derivative assets
$
2,493

 
$
4

 
$
2,497

 
 
 
 
 
 
Current derivative liabilities
$
1,738

 
$
44

 
$
1,782

Long-term derivative liabilities
374

 
70

 
444

Total derivative liabilities
$
2,112

 
$
114

 
$
2,226

Net derivative asset (liabilities)
$
381

 
$
(110
)
 
$
271



 
March 31, 2015
 
December 31, 2014
 
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
$
4

 
$
117

 
$
4

 
$
112

Total derivatives designated as cash flow hedging instruments
$
4

 
$
117

 
$
4

 
$
112

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
2,565

 
$
2,097

 
$
2,493

 
$
2,112

Interest rate swaps
—

 
1

 
—

 
2

Total derivatives not designated as hedging instruments
$
2,565

 
$
2,098

 
$
2,493

 
$
2,114

Total derivatives
$
2,569

 
$
2,215

 
$
2,497

 
$
2,226


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 March 31, 2015 and December 31, 2014 (in millions):
 
 
March 31, 2015
 
 
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
 
$
2,037

 
$
(1,810
)
 
$
(227
)
 
$
—

Commodity forward contracts
 
528

 
(263
)
 
(1
)
 
264

Interest rate swaps
 
4

 
—

 
—

 
4

Total derivative assets
 
$
2,569

 
$
(2,073
)
 
$
(228
)
 
$
268

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,814
)
 
$
1,810

 
$
4

 
$
—

Commodity forward contracts
 
(283
)
 
263

 
10

 
(10
)
Interest rate swaps
 
(118
)
 
—

 
—

 
(118
)
Total derivative (liabilities)
 
$
(2,215
)
 
$
2,073

 
$
14

 
$
(128
)
Net derivative assets (liabilities)
 
$
354

 
$
—

 
$
(214
)
 
$
140

 
 
December 31, 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
 
$
2,134

 
$
(1,865
)
 
$
(269
)
 
$
—

Commodity forward contracts
 
359

 
(222
)
 
—

 
137

Interest rate swaps
 
4

 
—

 
—

 
4

Total derivative assets
 
$
2,497

 
$
(2,087
)
 
$
(269
)
 
$
141

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,870
)
 
$
1,865

 
$
5

 
$
—

Commodity forward contracts
 
(242
)
 
222

 
10

 
(10
)
Interest rate swaps
 
(114
)
 
—

 
—

 
(114
)
Total derivative (liabilities)
 
$
(2,226
)
 
$
2,087

 
$
15

 
$
(124
)
Net derivative assets (liabilities)
 
$
271

 
$
—

 
$
(254
)
 
$
17

____________
(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 6 for a further discussion of our collateral.
Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of 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 March 31,
 
2015
 
2014
Realized gain (loss)(1)
 
 
 
Commodity derivative instruments
$
59

 
$
(39
)
Total realized gain (loss)
$
59

 
$
(39
)
 
 
 
 
Mark-to-market gain (loss)(2)
 
 
 
Commodity derivative instruments
$
70

 
$
(73
)
Interest rate swaps
1

 
1

Total mark-to-market gain (loss)
$
71

 
$
(72
)
Total activity, net
$
130

 
$
(111
)
___________
(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 March 31,
 
2015
 
2014
Realized and mark-to-market gain (loss)
 
 
 
Derivatives contracts included in operating revenues
$
119

 
$
(237
)
Derivatives contracts included in fuel and purchased energy expense
10

 
125

Interest rate swaps included in interest expense
1

 
1

Total activity, net
$
130

 
$
(111
)

Derivatives Included in OCI and AOCI
We do not have any commodity derivative instruments that were designated as cash flow hedges during the three months ended March 31, 2015 and 2014. 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 March 31,
 
Three Months Ended March 31,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(3)(4)
 
2015
 
2014
 
2015
 
2014
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
(6
)
 
$
—

 
$
(12
)
 
$
(13
)
 
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 the three months ended March 31, 2015 and 2014.
(2)
We recorded an income tax expense of nil for each of the three months ended March 31, 2015 and 2014, 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 $154 million and $149 million at March 31, 2015 and December 31, 2014, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $13 million and $12 million at March 31, 2015 and December 31, 2014, respectively.
(4)
Includes a loss of nil and $5 million for the three months ended March 31, 2015 and 2014, 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 March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
 
December 31, 2014
Margin deposits(1)
$
107

 
$
96

Natural gas and power prepayments
21

 
22

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
128

 
$
118

 
 
 
 
Letters of credit issued
$
459

 
$
450

First priority liens under power and natural gas agreements
33

 
48

First priority liens under interest rate swap agreements
120

 
116

Total letters of credit and first priority liens with our counterparties
$
612

 
$
614

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
40

 
$
47

Letters of credit posted with us by our counterparties
60

 
61

Total margin deposits and letters of credit posted with us by our counterparties
$
100

 
$
108

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 5 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2015 and December 31, 2014, $115 million and $109 million, respectively, were included in margin deposits and other prepaid expense and $13 million and $9 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 Benefit

The table below shows our consolidated income tax benefit from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2015
 
2014
Income tax benefit
$
(1
)
 
$
(19
)
Effective tax rate
9
%
 
53
%

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. For the three months ended March 31, 2015 and 2014, our income tax benefit 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 2014 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. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs.
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 March 31, 2015, we had unrecognized tax benefits of $54 million. If recognized, $13 million of our unrecognized tax benefits could impact the annual effective tax rate and $41 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact on our effective tax rate. We had accrued interest and penalties of $11 million for income tax matters at March 31, 2015. We recognize interest and penalties related to unrecognized tax benefits in income tax benefit on our Consolidated Condensed Statements of Operations.
Earnings (Loss) per Share
Earnings (Loss) per Share
Loss per Share
We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for the three months ended March 31, 2015 and 2014, diluted loss per share for both periods are computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following items from diluted loss per common share for the three months ended March 31, 2015 and 2014, because they were anti-dilutive (shares in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Share-based awards
8,947

 
8,995

Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
Equity Classified Share-Based Awards
Stock-based compensation expense recognized for our equity classified share-based awards was $9 million for each of the three months ended March 31, 2015 and 2014, 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 three months ended March 31, 2015 and 2014. At March 31, 2015, there was unrecognized compensation cost of $44 million related to restricted stock which is expected to be recognized over a weighted average period of 1.7 years.
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2015, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2014
4,201,868

 
$
18.01

Granted
1,510,546

 
$
21.46

Forfeited
70,901

 
$
18.80

Vested
1,515,774

 
$
16.36

Nonvested — March 31, 2015
4,125,739

 
$
19.86


The total fair value of our restricted stock and restricted stock units that vested during the three months ended March 31, 2015 and 2014, was approximately $32 million and $29 million, respectively.
Liability Classified Share-Based Awards
Performance share units granted under the Equity Plan are settled in cash with payouts based on the relative performance of Calpine’s TSR over a three-year performance period 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 classified as a liability and 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 $2 million and $1 million for the three months ended March 31, 2015 and 2014, respectively.
A summary of our performance share unit activity for the three months ended March 31, 2015, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2014
867,479

 
$
21.93

Granted
340,730

 
$
23.91

Forfeited
37,235

 
$
21.99

Vested(1)
8,254

 
$
22.56

Nonvested — March 31, 2015
1,162,720

 
$
22.50


___________
(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.
For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2014 Form 10-K.
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, individually or in the aggregate, 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 were West (including geothermal), Texas and East (including Canada). We continue to evaluate the manner in which we assess our performance, including our segments, which may result in future changes to the composition of our geographic segments.
Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).
 
Three Months Ended March 31, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
515

 
$
581

 
$
550

 
$
—

 
$
1,646

Intersegment revenues
2

 
3

 
2

 
(7
)
 
—

Total operating revenues
$
517

 
$
584

 
$
552

 
$
(7
)
 
$
1,646

Commodity Margin
$
218

 
$
149

 
$
168

 
$
—

 
$
535

Add: Mark-to-market commodity activity, net and other(1)
119

 
41

 
(52
)
 
(7
)
 
101

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
106

 
89

 
72

 
(7
)
 
260

Depreciation and amortization expense
67

 
49

 
42

 
—

 
158

Sales, general and other administrative expense
10

 
17

 
10

 
—

 
37

Other operating expenses
10

 
2

 
8

 
—

 
20

(Income) from unconsolidated investments in power plants
—

 
—

 
(5
)
 
—

 
(5
)
Income (loss) from operations
144

 
33

 
(11
)
 
—

 
166

Interest expense, net of interest income
 
 
 
 
 
 
 
 
153

 Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
21

Loss before income taxes
 
 
 
 
 
 
 
 
$
(8
)
 
Three Months Ended March 31, 2014
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
491

 
$
647

 
$
827

 
$
—

 
$
1,965

Intersegment revenues
2

 
12

 
17

 
(31
)
 
—

Total operating revenues
$
493

 
$
659

 
$
844

 
$
(31
)
 
$
1,965

Commodity Margin(2)
$
202

 
$
121

 
$
322

 
$
—

 
$
645

Add: Mark-to-market commodity activity, net and other(1)
29

 
(46
)
 
(11
)
 
(9
)
 
(37
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
105

 
90

 
79

 
(9
)
 
265

Depreciation and amortization expense
60

 
42

 
51

 
—

 
153

Sales, general and other administrative expense
10

 
12

 
12

 
(1
)
 
33

Other operating expenses
12

 
2

 
7

 
1

 
22

(Income) from unconsolidated investments in power plants
—

 
—

 
(9
)
 
—

 
(9
)
Income (loss) from operations
44


(71
)

171


—

 
144

Interest expense, net of interest income
 
 
 
 
 
 
 
 
165

 Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
11

Loss before income taxes
 
 
 
 
 
 
 
 
$
(32
)
_________
(1)
Includes $(24) million and $(29) million of lease levelization and $4 million and $4 million of amortization expense for the three months ended March 31, 2015 and 2014, respectively.
(2)
Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $39 million for the three months ended March 31, 2014.
Basis of Presentation and Summary of Significant Accounting Policies (Policies)
New Accounting Pronouncements, Policy [Policy Text Block] 
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.

Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” This standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidated analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard is effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have but do not anticipate a material impact on our financial condition, results of operations or cash flows.

Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and requires retrospective adoption 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.

Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods and allows for either prospective or retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.
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, 2014, included in our 2014 Form 10-K. The results for interim periods are not 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.
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 are expected to 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 
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.
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 months ended March 31, 2015 and 2014, 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 Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product 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 March 31, 2015 and December 31, 2014 (in millions):

 
March 31, 2015
 
December 31, 2014
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
12

 
$
24

 
$
36

 
$
10

 
$
25

 
$
35

Rent reserve
2

 
—

 
2

 
4

 
—

 
4

Construction/major maintenance
60

 
17

 
77

 
54

 
17

 
71

Security/project/insurance
88

 
4

 
92

 
127

 
5

 
132

Other
—

 
2

 
2

 
—

 
2

 
2

Total
$
162

 
$
47

 
$
209

 
$
195

 
$
49

 
$
244

Schedule of Property, Plant and Equipment 
Property, Plant and Equipment, Net — At March 31, 2015 and December 31, 2014, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2015
 
December 31, 2014
 
Depreciable Lives
Buildings, machinery and equipment
$
16,092

 
$
16,059

 
3 – 47 Years
Geothermal properties
1,314

 
1,294

 
13 – 59 Years
Other
205

 
203

 
3 – 47 Years
 
17,611

 
17,556

 
 
Less: Accumulated depreciation
5,122

 
4,984

 
 
 
12,489

 
12,572

 
 
Land
119

 
120

 
 
Construction in progress
570

 
498

 
 
Property, plant and equipment, net
$
13,178

 
$
13,190

 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables)
Condensed Financial Statements [Table Text Block] 
The summarized financial data for Whitby for the three months ended March 31, 2015 and 2014, are set forth below (in millions):
Whitby
Condensed Statements of Operations
(Unaudited)

 
Three Months Ended March 31,
 
2015
 
2014
Revenues
$
15

 
$
15

Operating expenses
9

 
7

Net income
$
6

 
$
8

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 March 31,
 
 
2015
 
2014
Greenfield LP
 
$
(2
)
 
$
(5
)
Whitby
 
(3
)
 
(4
)
Total
 
$
(5
)
 
$
(9
)

Schedule of Equity Method Investments 
At March 31, 2015 and December 31, 2014, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
March 31, 2015
 
March 31, 2015
 
December 31, 2014
Greenfield LP
50%
 
$
69

 
$
78

Whitby
50%
 
19

 
17

Total investments in power plants
 
 
$
88

 
$
95

Debt (Tables)
Schedule of Long-term Debt Instruments 
Our debt at March 31, 2015 and December 31, 2014, was as follows (in millions):
 
March 31, 2015

December 31, 2014
Senior Unsecured Notes
$
3,450

 
$
2,800

First Lien Term Loans
2,792

 
2,799

First Lien Notes
1,928

 
2,075

Project financing, notes payable and other
1,762

 
1,810

CCFC Term Loans
1,592

 
1,596

Capital lease obligations
193

 
202

Subtotal
11,717

 
11,282

Less: Current maturities
197

 
199

Total long-term debt
$
11,520

 
$
11,083

Senior Unsecured Notes 
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
March 31, 2015
 
December 31, 2014
2023 Senior Unsecured Notes
$
1,250

 
$
1,250

2024 Senior Unsecured Notes
650

 
—

2025 Senior Unsecured Notes
1,550

 
1,550

Total Senior Unsecured Notes
$
3,450

 
$
2,800

First Lien Term Loans 
The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2015
 
December 31, 2014
2018 First Lien Term Loans
$
1,593

 
$
1,597

2019 First Lien Term Loan
814

 
816

2020 First Lien Term Loan
385

 
386

Total First Lien Term Loans
$
2,792

 
$
2,799

First Lien Notes 
The amounts outstanding under our First Lien Notes are summarized in the table below (in millions):
 
March 31, 2015
 
December 31, 2014
2022 First Lien Notes
$
745

 
$
745

2023 First Lien Notes(1)
693

 
840

2024 First Lien Notes
490

 
490

Total First Lien Notes
$
1,928

 
$
2,075

____________
(1)
On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, which is described in further detail above.
Schedule of Line of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
 
December 31, 2014
Corporate Revolving Facility(1)
$
202

 
$
223

CDHI
235

 
214

Various project financing facilities
186

 
207

Total
$
623

 
$
644

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments 
The following table details the fair values and carrying values of our debt instruments at March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
 
December 31, 2014
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
Senior Unsecured Notes
$
3,462

 
$
3,450

 
$
2,832

 
$
2,800

First Lien Term Loans
2,795

 
2,792

 
2,769

 
2,799

First Lien Notes
2,091

 
1,928

 
2,247

 
2,075

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

 
1,655

 
1,734

 
1,688

CCFC Term Loans
1,580

 
1,592

 
1,540

 
1,596

Total
$
11,619

 
$
11,417

 
$
11,122

 
$
10,958

____________
(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 March 31, 2015 and December 31, 2014, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2015
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
965

 
$
—

 
$
—

 
$
965

Margin deposits
107

 
—

 
—

 
107

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
2,037

 
—

 
—

 
2,037

Commodity forward contracts(2)
—

 
295

 
233

 
528

Interest rate swaps
—

 
4

 
—

 
4

Total assets
$
3,109

 
$
299

 
$
233

 
$
3,641

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
40

 
$
—

 
$
—

 
$
40

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,814

 
—

 
—

 
1,814

Commodity forward contracts(2)
—

 
253

 
30

 
283

Interest rate swaps
—

 
118

 
—

 
118

Total liabilities
$
1,854

 
$
371

 
$
30

 
$
2,255

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2014
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
896

 
$
—

 
$
—

 
$
896

Margin deposits
96

 
—

 
—

 
96

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
2,134

 
—

 
—

 
2,134

Commodity forward contracts(2)
—

 
195

 
164

 
359

Interest rate swaps
—

 
4

 
—

 
4

Total assets
$
3,126

 
$
199

 
$
164

 
$
3,489

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
47

 
$
—

 
$
—

 
$
47

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,870

 
—

 
—

 
1,870

Commodity forward contracts(2)
—

 
163

 
79

 
242

Interest rate swaps
—

 
114

 
—

 
114

Total liabilities
$
1,917

 
$
277

 
$
79

 
$
2,273

___________
(1)
As of March 31, 2015 and December 31, 2014, we had cash equivalents of $757 million and $679 million included in cash and cash equivalents and $208 million and $217 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 March 31, 2015 and December 31, 2014:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
March 31, 2015
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
201

 
Discounted cash flow
 
Market price (per MWh)
 
$13.43 — $123.25/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
74

 
Discounted cash flow
 
Market price (per MWh)
 
$14.00 — $122.79/MWh
Natural Gas Contracts
 
$
5

 
Discounted cash flow
 
Market price (per MMBtu)
 
$1.00 — $10.86/MMBtu
Power Congestion Products
 
$
9

 
Discounted cash flow
 
Market price (per MWh)
 
$(19.56) — $19.56/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 March 31,
 
 
2015
 
2014
Balance, beginning of period
 
$
85

 
$
14

Realized and mark-to-market gains (losses):
 
 
 
 
Included in net loss:
 
 
 
 
Included in operating revenues(1)
 
131

 
(10
)
Included in fuel and purchased energy expense(2)
 
3

 
5

Purchases and settlements:
 
 
 
 
Purchases
 
2

 
1

Settlements
 
(10
)
 
(3
)
Transfers in and/or out of level 3(3):
 
 
 
 
Transfers into level 3(4)
 
(1
)
 
—

Transfers out of level 3(5)
 
(7
)
 
1

Balance, end of period
 
$
203

 
$
8

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
134

 
$
(5
)
___________
(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 months ended March 31, 2015 and 2014.
(4)
We had $(1) million in losses transferred out of level 2 into level 3 for the three months ended March 31, 2015. There were no transfers out of level 2 into level 3 for the three months ended March 31, 2014.
(5)
We had $(7) million in gains and $1 million in losses transferred out of level 3 into level 2 for the three months ended March 31, 2015 and 2014, respectively, due to changes in market liquidity in various power markets.
Derivative Instruments (Tables)
Schedule of Notional Amounts of Outstanding Derivative Positions 
As of March 31, 2015 and December 31, 2014, 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
 
March 31, 2015
 
December 31, 2014
Power (MWh)
 
(79
)
 
(62
)
Natural gas (MMBtu)
 
693

 
291

Environmental credits (Tonnes)
 
1

 
—

Interest rate swaps
 
$
1,419

 
$
1,431

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 March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,858

 
$
—

 
$
1,858

Long-term derivative assets
707

 
4

 
711

Total derivative assets
$
2,565

 
$
4

 
$
2,569

 
 
 
 
 
 
Current derivative liabilities
$
1,600

 
$
43

 
$
1,643

Long-term derivative liabilities
497

 
75

 
572

Total derivative liabilities
$
2,097

 
$
118

 
$
2,215

Net derivative asset (liabilities)
$
468

 
$
(114
)
 
$
354


 
December 31, 2014
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
2,058

 
$
—

 
$
2,058

Long-term derivative assets
435

 
4

 
439

Total derivative assets
$
2,493

 
$
4

 
$
2,497

 
 
 
 
 
 
Current derivative liabilities
$
1,738

 
$
44

 
$
1,782

Long-term derivative liabilities
374

 
70

 
444

Total derivative liabilities
$
2,112

 
$
114

 
$
2,226

Net derivative asset (liabilities)
$
381

 
$
(110
)
 
$
271

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value 
 
March 31, 2015
 
December 31, 2014
 
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
$
4

 
$
117

 
$
4

 
$
112

Total derivatives designated as cash flow hedging instruments
$
4

 
$
117

 
$
4

 
$
112

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
2,565

 
$
2,097

 
$
2,493

 
$
2,112

Interest rate swaps
—

 
1

 
—

 
2

Total derivatives not designated as hedging instruments
$
2,565

 
$
2,098

 
$
2,493

 
$
2,114

Total derivatives
$
2,569

 
$
2,215

 
$
2,497

 
$
2,226

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 March 31, 2015 and December 31, 2014 (in millions):
 
 
March 31, 2015
 
 
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
 
$
2,037

 
$
(1,810
)
 
$
(227
)
 
$
—

Commodity forward contracts
 
528

 
(263
)
 
(1
)
 
264

Interest rate swaps
 
4

 
—

 
—

 
4

Total derivative assets
 
$
2,569

 
$
(2,073
)
 
$
(228
)
 
$
268

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,814
)
 
$
1,810

 
$
4

 
$
—

Commodity forward contracts
 
(283
)
 
263

 
10

 
(10
)
Interest rate swaps
 
(118
)
 
—

 
—

 
(118
)
Total derivative (liabilities)
 
$
(2,215
)
 
$
2,073

 
$
14

 
$
(128
)
Net derivative assets (liabilities)
 
$
354

 
$
—

 
$
(214
)
 
$
140

 
 
December 31, 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
 
$
2,134

 
$
(1,865
)
 
$
(269
)
 
$
—

Commodity forward contracts
 
359

 
(222
)
 
—

 
137

Interest rate swaps
 
4

 
—

 
—

 
4

Total derivative assets
 
$
2,497

 
$
(2,087
)
 
$
(269
)
 
$
141

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,870
)
 
$
1,865

 
$
5

 
$
—

Commodity forward contracts
 
(242
)
 
222

 
10

 
(10
)
Interest rate swaps
 
(114
)
 
—

 
—

 
(114
)
Total derivative (liabilities)
 
$
(2,226
)
 
$
2,087

 
$
15

 
$
(124
)
Net derivative assets (liabilities)
 
$
271

 
$
—

 
$
(254
)
 
$
17

____________
(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 6 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 March 31,
 
2015
 
2014
Realized gain (loss)(1)
 
 
 
Commodity derivative instruments
$
59

 
$
(39
)
Total realized gain (loss)
$
59

 
$
(39
)
 
 
 
 
Mark-to-market gain (loss)(2)
 
 
 
Commodity derivative instruments
$
70

 
$
(73
)
Interest rate swaps
1

 
1

Total mark-to-market gain (loss)
$
71

 
$
(72
)
Total activity, net
$
130

 
$
(111
)
___________
(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 March 31,
 
2015
 
2014
Realized and mark-to-market gain (loss)
 
 
 
Derivatives contracts included in operating revenues
$
119

 
$
(237
)
Derivatives contracts included in fuel and purchased energy expense
10

 
125

Interest rate swaps included in interest expense
1

 
1

Total activity, net
$
130

 
$
(111
)
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 March 31,
 
Three Months Ended March 31,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(3)(4)
 
2015
 
2014
 
2015
 
2014
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
(6
)
 
$
—

 
$
(12
)
 
$
(13
)
 
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 the three months ended March 31, 2015 and 2014.
(2)
We recorded an income tax expense of nil for each of the three months ended March 31, 2015 and 2014, 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 $154 million and $149 million at March 31, 2015 and December 31, 2014, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $13 million and $12 million at March 31, 2015 and December 31, 2014, respectively.
(4)
Includes a loss of nil and $5 million for the three months ended March 31, 2015 and 2014, 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 March 31, 2015 and December 31, 2014 (in millions):
 
March 31, 2015
 
December 31, 2014
Margin deposits(1)
$
107

 
$
96

Natural gas and power prepayments
21

 
22

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
128

 
$
118

 
 
 
 
Letters of credit issued
$
459

 
$
450

First priority liens under power and natural gas agreements
33

 
48

First priority liens under interest rate swap agreements
120

 
116

Total letters of credit and first priority liens with our counterparties
$
612

 
$
614

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
40

 
$
47

Letters of credit posted with us by our counterparties
60

 
61

Total margin deposits and letters of credit posted with us by our counterparties
$
100

 
$
108

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 5 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2015 and December 31, 2014, $115 million and $109 million, respectively, were included in margin deposits and other prepaid expense and $13 million and $9 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 benefit from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2015
 
2014
Income tax benefit
$
(1
)
 
$
(19
)
Effective tax rate
9
%
 
53
%
Earnings (Loss) per Share (Tables)
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share
We excluded the following items from diluted loss per common share for the three months ended March 31, 2015 and 2014, because they were anti-dilutive (shares in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Share-based awards
8,947

 
8,995

Stock-Based Compensation (Tables)
Schedule of Share-based Compensation, Activity [Table Text Block] 
A summary of our performance share unit activity for the three months ended March 31, 2015, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2014
867,479

 
$
21.93

Granted
340,730

 
$
23.91

Forfeited
37,235

 
$
21.99

Vested(1)
8,254

 
$
22.56

Nonvested — March 31, 2015
1,162,720

 
$
22.50


___________
(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 Restricted Stock and Restricted Stock Unit Activity 
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2015, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2014
4,201,868

 
$
18.01

Granted
1,510,546

 
$
21.46

Forfeited
70,901

 
$
18.80

Vested
1,515,774

 
$
16.36

Nonvested — March 31, 2015
4,125,739

 
$
19.86

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 March 31, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
515

 
$
581

 
$
550

 
$
—

 
$
1,646

Intersegment revenues
2

 
3

 
2

 
(7
)
 
—

Total operating revenues
$
517

 
$
584

 
$
552

 
$
(7
)
 
$
1,646

Commodity Margin
$
218

 
$
149

 
$
168

 
$
—

 
$
535

Add: Mark-to-market commodity activity, net and other(1)
119

 
41

 
(52
)
 
(7
)
 
101

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
106

 
89

 
72

 
(7
)
 
260

Depreciation and amortization expense
67

 
49

 
42

 
—

 
158

Sales, general and other administrative expense
10

 
17

 
10

 
—

 
37

Other operating expenses
10

 
2

 
8

 
—

 
20

(Income) from unconsolidated investments in power plants
—

 
—

 
(5
)
 
—

 
(5
)
Income (loss) from operations
144

 
33

 
(11
)
 
—

 
166

Interest expense, net of interest income
 
 
 
 
 
 
 
 
153

 Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
21

Loss before income taxes
 
 
 
 
 
 
 
 
$
(8
)
 
Three Months Ended March 31, 2014
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
491

 
$
647

 
$
827

 
$
—

 
$
1,965

Intersegment revenues
2

 
12

 
17

 
(31
)
 
—

Total operating revenues
$
493

 
$
659

 
$
844

 
$
(31
)
 
$
1,965

Commodity Margin(2)
$
202

 
$
121

 
$
322

 
$
—

 
$
645

Add: Mark-to-market commodity activity, net and other(1)
29

 
(46
)
 
(11
)
 
(9
)
 
(37
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
105

 
90

 
79

 
(9
)
 
265

Depreciation and amortization expense
60

 
42

 
51

 
—

 
153

Sales, general and other administrative expense
10

 
12

 
12

 
(1
)
 
33

Other operating expenses
12

 
2

 
7

 
1

 
22

(Income) from unconsolidated investments in power plants
—

 
—

 
(9
)
 
—

 
(9
)
Income (loss) from operations
44


(71
)

171


—

 
144

Interest expense, net of interest income
 
 
 
 
 
 
 
 
165

 Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
11

Loss before income taxes
 
 
 
 
 
 
 
 
$
(32
)
_________
(1)
Includes $(24) million and $(29) million of lease levelization and $4 million and $4 million of amortization expense for the three months ended March 31, 2015 and 2014, respectively.
(2)
Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $39 million for the three months ended March 31, 2014.
Basis of Presentation and Summary of Significant Accounting Policies (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Dec. 31, 2014
Accounting Policies [Line Items]
 
 
 
Current
$ 162 
 
$ 195 
Non-current
47 
 
49 
Total
209 
 
244 
Interest Costs Capitalized
5 
6 
 
Treasury Stock, Shares, Acquired
9.3 
 
 
Treasury Stock, Value, Acquired, Cost Method
202 
 
 
Treasury Stock Acquired, Average Cost Per Share
$ 21.57 
 
 
Adjustments Related to Tax Withholding for Share-based Compensation
10 
 
 
Debt Service
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
12 
 
10 
Non-current
24 
 
25 
Total
36 
 
35 
Rent Reserve
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
2 
 
4 
Non-current
0 
 
0 
Total
2 
 
4 
Construction Major Maintenance
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
60 
 
54 
Non-current
17 
 
17 
Total
77 
 
71 
Security Project Insurance
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
88 
 
127 
Non-current
4 
 
5 
Total
92 
 
132 
Other
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
0 
 
0 
Non-current
2 
 
2 
Total
$ 2 
 
$ 2 
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
Mar. 31, 2015
Mar. 31, 2014
Dec. 31, 2014
Property, Plant and Equipment [Line Items]
 
 
 
Interest Costs Capitalized
$ 5 
$ 6 
 
Buildings, machinery and equipment
16,092 
 
16,059 
Geothermal properties
1,314 
 
1,294 
Other
205 
 
203 
Property, Plant and Equipment, Gross
17,611 
 
17,556 
Less: Accumulated depreciation
5,122 
 
4,984 
Property, Plant and Equipment, Gross, Less Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
12,489 
 
12,572 
Land
119 
 
120 
Construction in progress
570 
 
498 
Property, plant and equipment, net
$ 13,178 
 
$ 13,190 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 88 
$ 95 
Greenfield [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
69 
78 
Equity Method Investment, Ownership Percentage
50.00% 
 
Whitby [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 19 
$ 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
Mar. 31, 2015
Mar. 31, 2014
(Income) from unconsolidated investments in power plants
$ (5)
$ (9)
Greenfield [Member]
 
 
(Income) from unconsolidated investments in power plants
(2)
(5)
Whitby [Member]
 
 
(Income) from unconsolidated investments in power plants
$ (3)
$ (4)
Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2015
MW
Mar. 31, 2014
Dec. 31, 2014
MW
Variable Interest Entity [Line Items]
 
 
 
Power generation capacity
10,365 
 
10,365 
Variable Interest Entity, Financial or Other Support, Amount
$ 0 
    
$ 40 
Equity Method Investment, Summarized Financial Information, Debt
310 
 
342 
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt
155 
 
171 
Greenfield [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Power generation capacity
1,038 
 
 
Equity Method Investment, Ownership Percentage
50.00% 
 
 
Distribution from equity method investee
0 
0 
 
Whitby [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Power generation capacity
50 
 
 
Equity Method Investment, Ownership Percentage
50.00% 
 
 
Distribution from equity method investee
$ 0 
$ 13 
 
Inland Empire Energy Center [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Power generation capacity
775 
 
 
Put Option Exercise Period
2,025 
 
 
Inland Empire Energy Center [Member] |
Minimum [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Call Option Exercise Period
2,017 
 
 
Inland Empire Energy Center [Member] |
Maximum [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Call Option Exercise Period
2,024 
 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants Condensed Financial Statements (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Operating revenues
$ 1,646 
$ 1,965 
Costs and Expenses
1,485 
1,830 
Net income (loss)
(7)
(13)
Whitby [Member]
 
 
Operating revenues
15 
15 
Costs and Expenses
9 
7 
Net income (loss)
$ 6 
$ 8 
Debt (Debt) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,619 
$ 11,122 
Debt and Capital Lease Obligations
11,717 
11,282 
Debt, Current
197 
199 
Long-term Debt, Excluding Current Maturities
11,520 
11,083 
Unsecured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
3,450 
2,800 
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,792 
2,799 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,928 
2,075 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,762 
1,810 
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,592 
1,596 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 193 
$ 202 
Debt Senior Unsecured Notes (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,619 
$ 11,122 
Senior Unsecured Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,250 
1,250 
Senior Unsecured Notes 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
650 
0 
Senior Unsecured Notes 2025 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,550 
1,550 
Unsecured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 3,450 
$ 2,800 
Debt (First Lien Term Loans) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,619 
$ 11,122 
First Lien Term Loans 2018 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,593 
1,597 
First Lien Term Loan 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
814 
816 
2020 First Lien Term Loan [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
385 
386 
First Lien Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 2,792 
$ 2,799 
Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,619 
$ 11,122 
2022 First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
745 
745 
First Lien Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
693 1
840 1
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
$ 1,928 
$ 2,075 
Debt (Letter of Credit) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 623 
$ 644 
Corporate Revolving Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
202 1
223 1
CDH [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
235 
214 
Various Project Financing Facilities [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 186 
$ 207 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
$ 11,619 
$ 11,122 
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,450 
2,800 
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,792 
2,799 
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,928 
2,075 
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,592 
1,596 
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
11,417 
10,958 
Reported Value Measurement [Member] |
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,450 
2,800 
Reported Value Measurement [Member] |
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,792 
2,799 
Reported Value Measurement [Member] |
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,928 
2,075 
Reported Value Measurement [Member] |
Notes Payable, Other Payable excluding Capital Leases [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,655 1
1,688 1
Reported Value Measurement [Member] |
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,592 
1,596 
Fair Value, Inputs, Level 2 [Member] |
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,462 
2,832 
Fair Value, Inputs, Level 2 [Member] |
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,795 
2,769 
Fair Value, Inputs, Level 2 [Member] |
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,091 
2,247 
Fair Value, Inputs, Level 2 [Member] |
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,580 
1,540 
Fair Value, Inputs, Level 3 [Member] |
Notes Payable, Other Payable excluding Capital Leases [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
$ 1,691 1
$ 1,734 1
Debt (Debt Textuals) (Details) (USD $)
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Dec. 31, 2014
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Interest Rate, Effective Percentage
5.50% 
6.20% 
 
Long-term Debt
$ 11,619,000,000 
 
$ 11,122,000,000 
Gains (Losses) on Extinguishment of Debt
(19,000,000)
(1,000,000)
 
Senior Unsecured Notes 2024 [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
650,000,000 
 
 
Debt Instrument, Interest Rate, Stated Percentage
5.50% 
 
 
Long-term Debt
650,000,000 
 
0 
Deferred Finance Costs, Net
9,000,000 
 
 
First Lien Notes 2023 [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Long-term Debt
693,000,000 1
 
840,000,000 1
Gains (Losses) on Extinguishment of Debt
(19,000,000)
 
 
Early Redemption Amount [Member] |
First Lien Notes 2023 [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Long-term Debt
$ 147,000,000 
 
 
Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 965 1
$ 896 1
Margin deposits
107 2
96 2
Commodity futures contracts
2,037 
2,134 
Commodity forward contracts
528 3
359 3
Interest Rate Swap Assets, Fair Value Disclosure
4 
4 
Total assets
3,641 
3,489 
Margin deposits held by us posted by our counterparties
40 2 4
47 2 4
Commodity futures contracts
1,814 
1,870 
Commodity forward contracts
283 3
242 3
Interest rate swaps
118 
114 
Liabilities, Fair Value Disclosure
2,255 
2,273 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
965 1
896 1
Margin deposits
107 
96 
Commodity futures contracts
2,037 
2,134 
Commodity forward contracts
0 3
0 3
Interest Rate Swap Assets, Fair Value Disclosure
0 
0 
Total assets
3,109 
3,126 
Margin deposits held by us posted by our counterparties
40 
47 
Commodity futures contracts
1,814 
1,870 
Commodity forward contracts
0 3
0 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
1,854 
1,917 
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
295 3
195 3
Interest Rate Swap Assets, Fair Value Disclosure
4 
4 
Total assets
299 
199 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
253 3
163 3
Interest rate swaps
118 
114 
Liabilities, Fair Value Disclosure
371 
277 
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
233 3
164 3
Interest Rate Swap Assets, Fair Value Disclosure
0 
0 
Total assets
233 
164 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
30 3
79 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
$ 30 
$ 79 
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) (USD $)
Mar. 31, 2015
Dec. 31, 2014
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
$ 354,000,000 
$ 271,000,000 
Power Contracts [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
201,000,000 
74,000,000 
Power Contracts [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
13.43 
14.00 
Power Contracts [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
123.25 
122.79 
Natural Gas [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
0 
5,000,000 
Natural Gas [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
 
1.00 
Natural Gas [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
 
10.86 
Power Congestion Products [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
0 
9,000,000 
Power Congestion Products [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
 
(19.56)
Power Congestion Products [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
 
$ 19.56 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Dec. 31, 2014
Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Balance, beginning of period
$ 85 
$ 14 
 
 
Included in net income:
 
 
 
 
Included in operating revenues
131 1
(10)1
 
 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense
3 2
5 2
 
 
Purchases, issuances and settlements:
 
 
 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases
2 
1 
 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements
(10)
(3)
 
 
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount
0 
0 
 
 
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount
0 
0 
 
 
Transfers into level 3
(1)3 4
0 3 4
 
 
Transfers out of Level 3
(7)3 5
1 3 5
 
 
Balance, end of period
203 
8 
 
 
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)
134 
(5)
 
 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
 
Cash and Cash Equivalents, at Carrying Value
796 
515 
717 
941 
Restricted Cash and Cash Equivalents
209 
 
244 
 
Fair Value Measurement [Domain]
 
 
 
 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
 
Cash and Cash Equivalents, at Carrying Value
757 
 
679 
 
Restricted Cash and Cash Equivalents
$ 208 
 
$ 217 
 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2015
MWh
Dec. 31, 2014
MWh
Power [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Nonmonetary Notional Amount, Energy Measure
(79)
(62)
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Nonmonetary Notional Amount, Energy Measure
693 
291 
Environmental Credits [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Nonmonetary Notional Amount, Mass
1 
0 
Interest Rate Swap [Member]
 
 
Derivative [Line Items]
 
 
Derivative, Notional Amount
$ 1,419 
$ 1,431 
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
$ 1,858 
$ 2,058 
Long-term derivative assets
711 
439 
Total derivative assets
2,569 
2,497 
Derivative liabilities, current
1,643 
1,782 
Long-term derivative liabilities
572 
444 
Total derivative liabilities
2,215 
2,226 
Derivative, Fair Value, Net
354 
271 
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
4 
4 
Total derivative liabilities
117 
112 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
2,565 
2,493 
Total derivative liabilities
2,098 
2,114 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
0 
0 
Derivative Assets, Noncurrent
4 
4 
Total derivative assets
4 
4 
Current derivative liabilities
43 
44 
Derivative Liabilities, Noncurrent
75 
70 
Total derivative liabilities
118 
114 
Derivative, Fair Value, Net
(114)
(110)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
4 
4 
Total derivative liabilities
117 
112 
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
0 
0 
Total derivative liabilities
1 
2 
Energy Related Derivative [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
1,858 
2,058 
Derivative Assets, Noncurrent
707 
435 
Total derivative assets
2,565 
2,493 
Current derivative liabilities
1,600 
1,738 
Derivative Liabilities, Noncurrent
497 
374 
Total derivative liabilities
2,097 
2,112 
Derivative, Fair Value, Net
468 
381 
Energy Related Derivative [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
2,565 
2,493 
Total derivative liabilities
$ 2,097 
$ 2,112 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Power contracts included in operating revenues
$ 1,646 
$ 1,965 
Natural gas contracts included in fuel and purchased energy expense
1,010 
1,357 
Interest expense
154 
166 
Gain (Loss) on Derivative Instruments, Net, Pretax
130 
(111)
Gain (Loss) on Sale of Derivatives
59 1
(39)1
Mark-to-market gain (loss)
71 2
(72)2
Power [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Power contracts included in operating revenues
119 
(237)
Interest Rate Swap [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Interest expense
1 
1 
Mark-to-market gain (loss)
1 2
1 2
Energy Related Derivative [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Gain (Loss) on Sale of Derivatives
59 1
(39)1
Mark-to-market gain (loss)
70 2
(73)2
Natural Gas [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Natural gas contracts included in fuel and purchased energy expense
$ 10 
$ 125 
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Interest expense
$ 154 
$ 166 
Interest Rate Swap [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
(6)1 2
0 1 2
Interest expense
1 
1 
Reclassification out of Accumulated Other Comprehensive Income [Member] |
Interest Rate Swap [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Interest expense
$ (12)1 2 3 4
$ (13)1 2 3 4
Derivative Instruments (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
Parent [Member]
Dec. 31, 2014
Parent [Member]
Mar. 31, 2015
Noncontrolling Interest [Member]
Dec. 31, 2014
Noncontrolling Interest [Member]
Derivatives, Fair Value [Line Items]
 
 
 
 
 
 
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax
$ 0 
$ 0 
 
 
 
 
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax
 
 
154 
149 
13 
12 
Derivative Instruments (Textuals) [Abstract]
 
 
 
 
 
 
Maximum length of time hedging using interest rate derivative instruments
9 years 
 
 
 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
16 
 
 
 
 
 
Collateral Already Posted, Aggregate Fair Value
10 
 
 
 
 
 
Additional Collateral, Aggregate Fair Value
8 
 
 
 
 
 
(Gain) Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net
0 
5 
 
 
 
 
Cash Flow Hedge (Gain) Loss to be Reclassified within Twelve Months
$ 46 
 
 
 
 
 
Derivative Instruments (Detail 5) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 2,569 
$ 2,497 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(2,073)
(2,087)
Derivative, Collateral, Obligation to Return Cash
(228)1
(269)1
Derivative Liability, Fair Value, Gross Liability
(2,215)
(2,226)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
2,073 
2,087 
Derivative, Collateral, Right to Reclaim Cash
14 1
15 1
Derivative, Fair Value, Net
354 
271 
Derivative Fair Value, Amount Not Offset Against Collateral, Net
0 
0 
Margin/Cash (Received) Posted Subject to Master Netting Arrangement
(214)1
(254)1
Derivative Asset, Fair Value, Amount Offset Against Collateral
268 
141 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(128)
(124)
Derivative, Fair Value, Amount Offset Against Collateral, Net
140 
17 
Commodity Exchange Traded Futures and Swaps Contracts [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
2,037 
2,134 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(1,810)
(1,865)
Derivative, Collateral, Obligation to Return Cash
(227)1
(269)1
Derivative Liability, Fair Value, Gross Liability
(1,814)
(1,870)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
1,810 
1,865 
Derivative, Collateral, Right to Reclaim Cash
4 1
5 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
528 
359 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(263)
(222)
Derivative, Collateral, Obligation to Return Cash
(1)1
0 1
Derivative Liability, Fair Value, Gross Liability
(283)
(242)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
263 
222 
Derivative, Collateral, Right to Reclaim Cash
10 1
10 1
Derivative Asset, Fair Value, Amount Offset Against Collateral
264 
137 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(10)
(10)
Interest Rate Swap [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
4 
4 
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
(118)
(114)
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
(114)
(110)
Derivative Asset, Fair Value, Amount Offset Against Collateral
4 
4 
Derivative Liability, Fair Value, Amount Offset Against Collateral
$ (118)
$ (114)
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2015
Dec. 31, 2014
Use of Collateral [Abstract]
 
 
Margin deposits
$ 107 1
$ 96 1
Natural gas and power prepayments
21 
22 
Total margin deposits and natural gas and power prepayments with our counterparties
128 2
118 2
Letters of credit issued
459 
450 
First priority liens under power and natural gas agreements
33 
48 
First priority liens under interest rate swap agreements
120 
116 
Total letters of credit and first priority liens with our counterparties
612 
614 
Margin deposits held by us posted by our counterparties
40 1 3
47 1 3
Letters of credit posted with us by our counterparties
60 
61 
Total margin deposits and letters of credit posted with us by our counterparties
100 
108 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
13 
9 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
$ 115 
$ 109 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Income Tax Contingency [Line Items]
 
 
Income tax (expense) benefit
$ 1 
$ 19 
Effective Income Tax Rate, Continuing Operations
9.00% 
53.00% 
Unrecognized Tax Benefits
54 
 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
13 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
11 
 
Unrecognized Tax Benefit Related to Deferred Tax Asset
$ 41 
 
Earnings (Loss) per Share (Details)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Earnings (Loss) per Share [Abstract]
 
 
Share-based awards
8,947 
8,995 
Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) (Restricted Stock [Member], USD $)
3 Months Ended
Mar. 31, 2015
Dec. 31, 2014
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
4,125,739 
4,201,868 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 19.86 
$ 18.01 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
1,510,546 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 21.46 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
70,901 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value
$ 18.80 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
1,515,774 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 16.36 
 
Stock-Based Compensation (Stock Based Compensation Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Allocated Share-based Compensation Expense
$ 9 
$ 9 
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards
2 
1 
Restricted Stock [Member]
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
44 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
1 year 8 months 12 days 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
$ 32 
$ 29 
Stock-Based Compensation Liability Based Stock Compensation (Details) (Performance Shares [Member], USD $)
3 Months Ended
Mar. 31, 2015
Dec. 31, 2014
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, Number
1,162,720 
867,479 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 22.50 
$ 21.93 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
340,730 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 23.91 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
37,235 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value
$ 21.99 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
8,254 1
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 22.56 
 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Mar. 31, 2015
Mar. 31, 2014
Mar. 31, 2015
West [Member]
Mar. 31, 2014
West [Member]
Mar. 31, 2015
Texas [Member]
Mar. 31, 2014
Texas [Member]
Mar. 31, 2015
East [Member]
Mar. 31, 2014
East [Member]
Mar. 31, 2015
Geography Consolidation and Elimination [Member]
Mar. 31, 2014
Geography Consolidation and Elimination [Member]
Mar. 31, 2014
Six Power Plants [Member]
Mar. 31, 2015
Operating Segments [Member]
Mar. 31, 2014
Operating Segments [Member]
Mar. 31, 2015
Operating Segments [Member]
West [Member]
Mar. 31, 2014
Operating Segments [Member]
West [Member]
Mar. 31, 2015
Operating Segments [Member]
Texas [Member]
Mar. 31, 2014
Operating Segments [Member]
Texas [Member]
Mar. 31, 2015
Operating Segments [Member]
East [Member]
Mar. 31, 2014
Operating Segments [Member]
East [Member]
Mar. 31, 2015
Operating Segments [Member]
Geography Consolidation and Elimination [Member]
Mar. 31, 2014
Operating Segments [Member]
Geography Consolidation and Elimination [Member]
Mar. 31, 2015
Intersegment Eliminations [Member]
Mar. 31, 2014
Intersegment Eliminations [Member]
Mar. 31, 2015
Intersegment Eliminations [Member]
West [Member]
Mar. 31, 2014
Intersegment Eliminations [Member]
West [Member]
Mar. 31, 2015
Intersegment Eliminations [Member]
Texas [Member]
Mar. 31, 2014
Intersegment Eliminations [Member]
Texas [Member]
Mar. 31, 2015
Intersegment Eliminations [Member]
East [Member]
Mar. 31, 2014
Intersegment Eliminations [Member]
East [Member]
Mar. 31, 2015
Intersegment Eliminations [Member]
Geography Consolidation and Elimination [Member]
Mar. 31, 2014
Intersegment Eliminations [Member]
Geography Consolidation and Elimination [Member]
Jun. 30, 2014
Six Power Plants [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 1,646 
$ 1,965 
$ 517 
$ 493 
$ 584 
$ 659 
$ 552 
$ 844 
$ (7)
$ (31)
 
$ 1,646 
$ 1,965 
$ 515 
$ 491 
$ 581 
$ 647 
$ 550 
$ 827 
$ 0 
$ 0 
$ 0 
$ 0 
$ 2 
$ 2 
$ 3 
$ 12 
$ 2 
$ 17 
$ (7)
$ (31)
 
Commodity Margin
535 1
645 1
218 1
202 1
149 1
121 1
168 1
322 1
0 1
0 1
39 1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Add: Mark-to-market commodity activity, net and other
101 2
(37)2
119 2
29 2
41 2
(46)2
(52)2
(11)2
(7)2
(9)2
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
260 
265 
106 
105 
89 
90 
72 
79 
(7)
(9)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization expense
158 
153 
67 
60 
49 
42 
42 
51 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales, general and other administrative expense
37 
33 
10 
10 
17 
12 
10 
12 
0 
(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other operating expenses
20 
22 
10 
12 
2 
2 
8 
7 
0 
1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Income) loss from unconsolidated investments in power plants
(5)
(9)
0 
0 
0 
0 
(5)
(9)
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income from operations
166 
144 
144 
44 
33 
(71)
(11)
171 
0 
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net of interest income
153 
165 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt extinguishment costs and other (income) expense, net
21 
11 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss before income taxes
(8)
(32)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease levelization
(24)
(29)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contract amortization
$ 4 
$ 4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of power plants disposed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6