CALPINE CORP, 10-Q filed on 4/29/2016
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2016
Apr. 27, 2016
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, 2016 
 
Document Fiscal Year Focus
2016 
 
Document Fiscal Period Focus
Q1 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
359,026,393 
Consolidated Condensed Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Operating revenues:
 
 
Commodity revenue
$ 1,585 
$ 1,638 
Mark-to-market gain
25 
Other revenue
Operating revenues
1,615 
1,646 
Operating expenses:
 
 
Commodity expense
1,006 
1,077 
Mark-to-market (gain) loss
120 
(67)
Fuel and purchased energy expense
1,126 
1,010 
Plant operating expense
255 
260 
Depreciation and amortization expense
180 
158 
Sales, general and other administrative expense
38 
37 
Other operating expenses
20 
20 
Total operating expenses
1,619 
1,485 
(Income) from unconsolidated investments in power plants
(7)
(5)
Income from operations
166 
Interest expense
157 
154 
Interest (income)
(1)
(1)
Debt extinguishment costs
19 
Other (income) expense, net
Loss before income taxes
(159)
(8)
Income tax expense (benefit)
35 
(1)
Net income (loss)
(194)
(7)
Net income attributable to the noncontrolling interest
(4)
(3)
Net loss attributable to Calpine
$ (198)
$ (10)
Basic and diluted loss per common share attributable to Calpine:
 
 
Weighted average number of shares outstanding, basic and diluted
353,501 
372,935 
Earnings per share, basic and diluted
$ (0.56)
$ (0.03)
Consolidated Condensed Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
 
 
Net loss
$ (194)
$ (7)
Cash flow hedging activities:
 
 
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss
(23)
(18)
Reclassification adjustment for loss on cash flow hedges realized in net loss
11 
12 
Foreign currency translation gain (loss)
12 
(12)
Income tax expense
Other comprehensive income (loss)
(18)
Comprehensive loss
(194)
(25)
Comprehensive (income) attributable to the noncontrolling interest
(2)
(2)
Comprehensive loss attributable to Calpine
$ (196)
$ (27)
Consolidated Condensed Balance Sheets (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Current assets:
 
 
Cash and cash equivalents ($48 and $118 attributable to VIEs)
$ 244 
$ 906 
Accounts receivable, net of allowance of $3 and $2
569 
644 
Inventories
490 
475 
Margin deposits and other prepaid expense
149 
137 
Restricted cash, current ($110 and $132 attributable to VIEs)
167 
216 
Derivative assets, current
1,853 
1,698 
Other current assets
303 
19 
Total current assets
3,775 
4,095 
Property, plant and equipment, net ($4,024 and $4,062 attributable to VIEs)
13,407 
13,012 
Restricted cash, net of current portion ($17 and $11 attributable to VIEs)
17 
12 
Investments in power plants
89 
79 
Long-term derivative assets
420 
313 
Assets Held-for-sale, Not Part of Disposal Group
130 
Other assets ($107 and $166 attributable to VIEs)
951 
1,040 
Total assets
18,659 
18,681 
Current liabilities:
 
 
Accounts payable
433 
552 
Accrued interest payable
124 
129 
Debt, current portion ($165 and $166 attributable to VIEs)
205 
221 
Derivative liabilities, current
1,975 
1,734 
Other current liabilities
348 
412 
Total current liabilities
3,085 
3,048 
Debt, net of current portion ($3,055 and $3,143 attributable to VIEs)
11,672 
11,716 
Long-term derivative liabilities
585 
473 
Other long-term liabilities
344 
277 
Total liabilities
15,686 
15,514 
Commitments and contingencies (see Note 11)
   
   
Stockholders’ equity:
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 359,542,565 and 356,755,747 shares issued, respectively, and 359,027,395 and 356,662,004 shares outstanding, respectively
Treasury stock, at cost, 515,170 and 93,743 shares, respectively
(7)
(1)
Additional paid-in capital
9,602 
9,594 
Accumulated deficit
(6,503)
(6,305)
Accumulated other comprehensive loss
(177)
(179)
Total Calpine stockholders’ equity
2,915 
3,109 
Noncontrolling interest
58 
58 
Total stockholders’ equity
2,973 
3,167 
Total liabilities and stockholders’ equity
$ 18,659 
$ 18,681 
Consolidated Condensed Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Cash and cash equivalents ($48 and $118 attributable to VIEs)
$ 244 
$ 906 
Accounts receivable, net of allowance of $3 and $2
Restricted cash, current ($110 and $132 attributable to VIEs)
167 
216 
Property, plant and equipment, net ($4,024 and $4,062 attributable to VIEs)
13,407 
13,012 
Restricted cash, net of current portion ($17 and $11 attributable to VIEs)
17 
12 
Other assets ($107 and $166 attributable to VIEs)
951 
1,040 
Debt, current portion ($165 and $166 attributable to VIEs)
205 
221 
Debt, net of current portion ($3,055 and $3,143 attributable to VIEs)
11,672 
11,716 
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
Preferred Stock, Shares Outstanding
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
359,542,565 
356,755,747 
Common Stock, Shares, Outstanding
359,027,395 
356,662,004 
Treasury Stock, Shares
515,170 
93,743 
Variable Interest Entity, Primary Beneficiary [Member]
 
 
Cash and cash equivalents ($48 and $118 attributable to VIEs)
48 
118 
Restricted cash, current ($110 and $132 attributable to VIEs)
110 
132 
Property, plant and equipment, net ($4,024 and $4,062 attributable to VIEs)
4,024 
4,062 
Restricted cash, net of current portion ($17 and $11 attributable to VIEs)
17 
11 
Other assets ($107 and $166 attributable to VIEs)
107 
166 
Debt, current portion ($165 and $166 attributable to VIEs)
165 
166 
Debt, net of current portion ($3,055 and $3,143 attributable to VIEs)
$ 3,055 
$ 3,143 
Consolidated Condensed Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Cash flows from operating activities:
 
 
Net loss
$ (194)
$ (7)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
Depreciation and amortization(1)
226 1
171 1
Income tax expense
35 
Mark-to-market activity, net
94 2
(71)2
(Income) from unconsolidated investments in power plants
(7)
(5)
Stock-based compensation expense
11 
Other Noncash Income (Expense)
(4)
(2)
Change in operating assets and liabilities, net of effect of acquisition:
 
 
Accounts receivable
87 
120 
Derivative instruments, net
(12)
(17)
Other assets
(19)
(28)
Accounts payable and accrued expenses
(207)
(204)
Other liabilities
18 
15 
Net cash provided by (used in) operating activities
26 
(17)
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(133)
(162)
Purchase of Granite Ridge Energy Center
(527)
Decrease in restricted cash
43 
35 
Other
(1)
Net cash used in investing activities
(611)
(128)
Cash flows from financing activities:
 
 
Repayment of CCFC Term Loans and First Lien Term Loans
(13)
(11)
Borrowings under Senior Unsecured Notes
650 
Repurchase of First Lien Notes
(147)
Repayments of project financing, notes payable and other
(56)
(58)
Distribution to noncontrolling interest holder
Financing costs
(7)
(11)
Stock repurchases
(202)
Proceeds from exercises of stock options
Proceeds from (Payments for) Other Financing Activities
Net cash provided by (used in) financing activities
(77)
224 
Net increase (decrease) in cash and cash equivalents
(662)
79 
Cash and cash equivalents, beginning of period
906 
717 
Cash and cash equivalents, end of period
244 
796 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
150 
146 
Income taxes
Supplemental disclosure of non-cash investing activities:
 
 
Change in capital expenditures included in accounts payable
$ 15 
$ (22)
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 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 and Mid-Atlantic regions (included in our East segment) of the U.S. We sell 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 and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. 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, environmental product, fuel oil and other physical and financial commodity 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, 2015, included in our 2015 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.
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 cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts 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, making these cash funds unavailable for general use. 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 and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.
The table below represents the components of our restricted cash as of March 31, 2016 and December 31, 2015 (in millions):

 
March 31, 2016
 
December 31, 2015
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
29

 
$
7

 
$
36

 
$
28

 
$
8

 
$
36

Construction/major maintenance
45

 
7

 
52

 
50

 
2

 
52

Security/project/insurance
91

 
1

 
92

 
136

 

 
136

Other
2

 
2

 
4

 
2

 
2

 
4

Total
$
167

 
$
17

 
$
184

 
$
216

 
$
12

 
$
228


Property, Plant and Equipment, Net — At March 31, 2016 and December 31, 2015, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2016
 
December 31, 2015
 
Depreciable Lives
Buildings, machinery and equipment
$
16,685

 
$
16,294

 
3 – 46 Years
Geothermal properties
1,327

 
1,319

 
13 – 58 Years
Other
219

 
208

 
3 – 46 Years
 
18,231

 
17,821

 
 
Less: Accumulated depreciation
5,491

 
5,377

 
 
 
12,740

 
12,444

 
 
Land
121

 
120

 
 
Construction in progress
546

 
448

 
 
Property, plant and equipment, net
$
13,407

 
$
13,012

 
 
Capitalized Interest — The total amount of interest capitalized was $4 million and $5 million for the three months ended March 31, 2016 and 2015, respectively.
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 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. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In addition, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” in March 2016 which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. We are currently assessing the future impact the revenue recognition 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 consolidation 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 adopted Accounting Standards Update 2015-02 in the first quarter of 2016 which did not have 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. In August 2015, the FASB issued Accounting Standards Update 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” which allows an entity to present debt issuance costs associated with a line-of-credit arrangement as an asset regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The standards are effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and require retrospective adoption with early adoption permitted. We retrospectively adopted Accounting Standard Updates 2015-03 and 2015-15 in the first quarter of 2016 which resulted in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion on our Consolidated Condensed Balance Sheet at December 31, 2015.

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 adopted Accounting Standards Update 2015-05 in the first quarter of 2016 which did not have a material impact on our financial condition, results of operations or cash flows.

Inventory In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” This standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective 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.

Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified 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.

Stock-Based Compensation In March 2016, the FASB issued Accounting Standards Update 2016-09, “Improvements to Employee Share-Based Payment Accounting.” This standard applies to several aspects of accounting for stock-based compensation including the recognition of excess tax benefits and deficiencies and their related presentation in the statement of cash flows as well as accounting for forfeitures. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and allows for prospective, retrospective or modified retrospective adoption, depending on the area covered in the update, 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 as a result of adopting this standard.
Acquisition (Notes)
Mergers, acquisitions and dispositions disclosures
Acquisitions and Divestitures
Acquisition of Granite Ridge Energy Center
On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Beginning operations in 2003, Granite Ridge Energy Center is located in Londonderry, New Hampshire and features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and financing obtained in the fourth quarter of 2015, and the purchase price was primarily allocated to property, plant and equipment. The pro forma incremental impact of Granite Ridge Energy Center on our results of operations for each of the three months ended March 31, 2016 and 2015 is not material.
Acquisition of Champion Energy
On October 1, 2015, we, through our indirect, wholly-owned subsidiary Calpine Energy Services Holdco, LLC, completed the purchase of Champion Energy Marketing, LLC from a subsidiary of Crane Champion Holdco, LLC, which owned a 75% interest, and EDF Trading North America, LLC, which owned a 25% interest, for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve. The purchase price was funded with cash on hand and any excess of the purchase price over the fair values of Champion Energy’s assets and liabilities was recorded as goodwill; however, the goodwill we recorded as a result of this acquisition was immaterial. We did not record any material adjustments to the preliminary purchase price allocation during the three months ended March 31, 2016.
Sale of South Point Energy Center
On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peak capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration.
Assets Held for Sale
The assets of Osprey Energy Center and South Point Energy Center, which are part of our East and West segments, respectively, are classified as held for sale and are reported as other current assets on our Consolidated Condensed Balance Sheet at March 31, 2016 and consist of property, plant and equipment, net.
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, 2016. See Note 5 in our 2015 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 10,266 MW at both March 31, 2016 and December 31, 2015. 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 during each of the three months ended March 31, 2016 and 2015.
Unconsolidated VIEs and Investments in Power Plants
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are 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, 2016 and December 31, 2015, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
March 31, 2016
 
March 31, 2016
 
December 31, 2015
Greenfield LP
50%
 
$
71

 
$
65

Whitby
50%
 
18

 
14

Total investments in power plants
 
 
$
89

 
$
79


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, 2016 and December 31, 2015, equity method investee debt was approximately $284 million and $269 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $142 million and $135 million at March 31, 2016 and December 31, 2015, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the three months ended March 31, 2016 and 2015, is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):
 
 
Three Months Ended March 31,
 
 
2016
 
2015
Greenfield LP
 
$
(4
)
 
$
(2
)
Whitby
 
(3
)
 
(3
)
Total
 
$
(7
)
 
$
(5
)

Distributions from Greenfield LP and Whitby were nil during each of the three months ended March 31, 2016 and 2015.
Debt
Debt
Debt
We retrospectively adopted Accounting Standards Update 2015-03 in the first quarter of 2016. As a result, we recast our Consolidated Condensed Balance Sheet at December 31, 2015 resulting in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion. Our debt at March 31, 2016 and December 31, 2015, was as follows (in millions):
 
March 31, 2016

December 31, 2015
Senior Unsecured Notes
$
3,408

 
$
3,406

First Lien Term Loans
3,271

 
3,277

First Lien Notes
1,790

 
1,789

Project financing, notes payable and other
1,665

 
1,715

CCFC Term Loans
1,562

 
1,565

Capital lease obligations
181

 
185

Subtotal
11,877

 
11,937

Less: Current maturities
205

 
221

Total long-term debt
$
11,672

 
$
11,716


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, 2016, from 5.7% for the same period in 2015. The issuance of our Senior Unsecured Notes in February 2015 and our 2022 First Lien Term Loan in May 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and all of our 2018 First Lien Term Loans with 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, 2016
 
December 31, 2015
2023 Senior Unsecured Notes
$
1,235

 
$
1,235

2024 Senior Unsecured Notes
642

 
641

2025 Senior Unsecured Notes
1,531

 
1,530

Total Senior Unsecured Notes
$
3,408

 
$
3,406


First Lien Term Loans
The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2016
 
December 31, 2015
2019 First Lien Term Loan
$
794

 
$
795

2020 First Lien Term Loan
377

 
378

2022 First Lien Term Loan
1,568

 
1,571

2023 First Lien Term Loan
532

 
533

Total First Lien Term Loans
$
3,271

 
$
3,277


First Lien Notes
The amounts outstanding under our First Lien Notes are summarized in the table below (in millions):
 
March 31, 2016
 
December 31, 2015
2022 First Lien Notes
$
738

 
$
737

2023 First Lien Notes
568

 
568

2024 First Lien Notes
484

 
484

Total First Lien Notes
$
1,790

 
$
1,789


Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at March 31, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
 
December 31, 2015
Corporate Revolving Facility(1)
$
314

 
$
316

CDHI
262

 
241

Various project financing facilities
178

 
198

Total
$
754

 
$
755

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.
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, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
 
December 31, 2015
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
3,315

 
$
3,408

 
$
3,063

 
$
3,406

First Lien Term Loans
3,290

 
3,271

 
3,197

 
3,277

First Lien Notes
1,906

 
1,790

 
1,885

 
1,789

Project financing, notes payable and other(1)
1,619

 
1,574

 
1,653

 
1,608

CCFC Term Loans
1,544

 
1,562

 
1,494

 
1,565

Total
$
11,674

 
$
11,605

 
$
11,292

 
$
11,645

____________
(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 in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. 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 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, 2016 and December 31, 2015, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2016
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
376

 
$

 
$

 
$
376

Margin deposits
94

 

 

 
94

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,967

 

 

 
1,967

Commodity forward contracts(2)

 
250

 
55

 
305

Interest rate swaps

 
1

 

 
1

Total assets
$
2,437

 
$
251

 
$
55

 
$
2,743

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

 
$

 
$

 
$
22

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,874

 

 

 
1,874

Commodity forward contracts(2)

 
468

 
120

 
588

Interest rate swaps

 
98

 

 
98

Total liabilities
$
1,896

 
$
566

 
$
120

 
$
2,582

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2015
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,083

 
$

 
$

 
$
1,083

Margin deposits
89

 

 

 
89

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,736

 

 

 
1,736

Commodity forward contracts(2)

 
220

 
54

 
274

Interest rate swaps

 
1

 

 
1

Total assets
$
2,908

 
$
221

 
$
54

 
$
3,183

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
35

 
$

 
$

 
$
35

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,604

 

 

 
1,604

Commodity forward contracts(2)

 
413

 
100

 
513

Interest rate swaps

 
90

 

 
90

Total liabilities
$
1,639

 
$
503

 
$
100

 
$
2,242

___________
(1)
As of March 31, 2016 and December 31, 2015, we had cash equivalents of $216 million and $880 million included in cash and cash equivalents and $160 million and $203 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
At March 31, 2016 and December 31, 2015, 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, 2016 and December 31, 2015:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
March 31, 2016
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(77
)
 
Discounted cash flow
 
Market price (per MWh)
 
$4.95 — $100.54/MWh
Power Congestion Products
 
$
12

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.33) — $10.38/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(54
)
 
Discounted cash flow
 
Market price (per MWh)
 
$6.72 — $83.25/MWh
Power Congestion Products
 
$
8

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.47) — $12.19/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,
 
 
2016
 
2015
Balance, beginning of period
 
$
(46
)
 
$
85

Realized and mark-to-market gains (losses):
 
 
 
 
Included in net loss:
 
 
 
 
Included in operating revenues(1)
 
(22
)
 
131

Included in fuel and purchased energy expense(2)
 
(14
)
 
3

Purchases and settlements:
 
 
 
 
Purchases
 
2

 
2

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

 
(1
)
Transfers out of level 3(5)
 
19

 
(7
)
Balance, end of period
 
$
(65
)
 
$
203

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
(36
)
 
$
134

___________
(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, 2016 and 2015.
(4)
There were no transfers out of level 2 into level 3 for the three months ended March 31, 2016. We had $1 million in losses transferred out of level 2 into level 3 for the three months ended March 31, 2015.
(5)
We had $(19) million in losses and $7 million in gains transferred out of level 3 into level 2 for the three months ended March 31, 2016 and 2015, 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, fuel oil, 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 related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. 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, 2016 and 2015.
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, 2016, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 8 years.
As of March 31, 2016 and December 31, 2015, 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, 2016
 
December 31, 2015
Power (MWh)
 
(49
)
 
(41
)
Natural gas (MMBtu)
 
1,065

 
996

Environmental credits (Tonnes)
 
17

 
8

Interest rate swaps
 
$
1,308

 
$
1,320


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, 2016, was $57 million for which we have posted collateral of $7 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 $14 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 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 only apply hedge accounting to our interest rate derivative instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate swaps designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on 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, environmental product and fuel oil 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, power, environmental product and fuel oil 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, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,853

 
$

 
$
1,853

Long-term derivative assets
419

 
1

 
420

Total derivative assets
$
2,272

 
$
1

 
$
2,273

 
 
 
 
 
 
Current derivative liabilities
$
1,938

 
$
37

 
$
1,975

Long-term derivative liabilities
524

 
61

 
585

Total derivative liabilities
$
2,462

 
$
98

 
$
2,560

Net derivative assets (liabilities)
$
(190
)
 
$
(97
)
 
$
(287
)

 
December 31, 2015
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,698

 
$

 
$
1,698

Long-term derivative assets
312

 
1

 
313

Total derivative assets
$
2,010

 
$
1

 
$
2,011

 
 
 
 
 
 
Current derivative liabilities
$
1,697

 
$
37

 
$
1,734

Long-term derivative liabilities
420

 
53

 
473

Total derivative liabilities
$
2,117

 
$
90

 
$
2,207

Net derivative assets (liabilities)
$
(107
)
 
$
(89
)
 
$
(196
)


 
March 31, 2016
 
December 31, 2015
 
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
$
1

 
$
100

 
$
1

 
$
92

Total derivatives designated as cash flow hedging instruments
$
1

 
$
100

 
$
1

 
$
92

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
2,272

 
$
2,462

 
$
2,010

 
$
2,117

Interest rate swaps

 
(2
)
 

 
(2
)
Total derivatives not designated as hedging instruments
$
2,272

 
$
2,460

 
$
2,010

 
$
2,115

Total derivatives
$
2,273

 
$
2,560

 
$
2,011

 
$
2,207


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, 2016 and December 31, 2015 (in millions):
 
 
March 31, 2016
 
 
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
 
$
1,967

 
$
(1,874
)
 
$
(93
)
 
$

Commodity forward contracts
 
305

 
(230
)
 
(7
)
 
68

Interest rate swaps
 
1

 

 

 
1

Total derivative assets
 
$
2,273

 
$
(2,104
)
 
$
(100
)
 
$
69

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,874
)
 
$
1,874

 
$

 
$

Commodity forward contracts
 
(588
)
 
230

 
1

 
(357
)
Interest rate swaps
 
(98
)
 

 

 
(98
)
Total derivative (liabilities)
 
$
(2,560
)
 
$
2,104

 
$
1

 
$
(455
)
Net derivative assets (liabilities)
 
$
(287
)
 
$

 
$
(99
)
 
$
(386
)
 
 
December 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
 
$
1,736

 
$
(1,602
)
 
$
(134
)
 
$

Commodity forward contracts
 
274

 
(202
)
 
(3
)
 
69

Interest rate swaps
 
1

 

 

 
1

Total derivative assets
 
$
2,011

 
$
(1,804
)
 
$
(137
)
 
$
70

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,604
)
 
$
1,602

 
$
2

 
$

Commodity forward contracts
 
(513
)
 
202

 
3

 
(308
)
Interest rate swaps
 
(90
)
 

 

 
(90
)
Total derivative (liabilities)
 
$
(2,207
)
 
$
1,804

 
$
5

 
$
(398
)
Net derivative assets (liabilities)
 
$
(196
)
 
$

 
$
(132
)
 
$
(328
)
____________
(1)
Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral.
Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
 
 
Three Months Ended March 31,
 
 
2016
 
2015
Realized gain (loss)(1)(2)
 
 
 
 
Commodity derivative instruments
 
$
118

 
$
59

Total realized gain (loss)
 
$
118

 
$
59

 
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
 
Commodity derivative instruments
 
$
(95
)
 
$
70

Interest rate swaps
 
1

 
1

Total mark-to-market gain (loss)
 
$
(94
)
 
$
71

Total activity, net
 
$
24

 
$
130

___________
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
Includes amortization of acquisition date fair value of derivative activity related to the acquisition of Champion Energy.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
 
Three Months Ended March 31,
 
 
2016
 
2015
Realized and mark-to-market gain (loss)
 
 
 
 
Derivatives contracts included in operating revenues(1)
 
$
204

 
$
119

Derivatives contracts included in fuel and purchased energy expense(1)
 
(181
)
 
10

Interest rate swaps included in interest expense
 
1

 
1

Total activity, net
 
$
24

 
$
130


___________
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
Derivatives Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):
 
Three Months Ended March 31,
 
Three Months Ended March 31,
 
Gain (Loss) Recognized in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(3)
 
2016
 
2015
 
2016
 
2015
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
(12
)
 
$
(6
)
 
$
(11
)
 
$
(12
)
 
Interest expense
____________
(1)
We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three months ended March 31, 2016 and 2015.
(2)
We recorded an income tax expense of nil for each of the three months ended March 31, 2016 and 2015, 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 $137 million and $127 million at March 31, 2016 and December 31, 2015, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $13 million and $11 million at March 31, 2016 and December 31, 2015, respectively.
We estimate that pre-tax net losses of $41 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, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
 
December 31, 2015
Margin deposits(1)
$
94

 
$
89

Natural gas and power prepayments
36

 
34

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
130

 
$
123

 
 
 
 
Letters of credit issued
$
629

 
$
600

First priority liens under power and natural gas agreements(3)
389

 
382

First priority liens under interest rate swap agreements
100

 
92

Total letters of credit and first priority liens with our counterparties
$
1,118

 
$
1,074

 
 
 
 
Margin deposits posted with us by our counterparties(1)(4)
$
22

 
$
35

Letters of credit posted with us by our counterparties
39

 
24

Total margin deposits and letters of credit posted with us by our counterparties
$
61

 
$
59

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2016 and December 31, 2015, $116 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $14 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Includes $364 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at March 31, 2016 and December 31, 2015, respectively.
(4)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.
Income Taxes
Income Taxes
Income Taxes
Income Tax Expense (Benefit)

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2016
 
2015
Income tax expense (benefit)
$
35

 
$
(1
)
Effective tax rate
(21
)%
 
9
%

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, 2016 and 2015, our income tax expense (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 2015 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 history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At March 31, 2016, we had unrecognized tax benefits of $57 million. If recognized, $17 million of our unrecognized tax benefits could impact the annual effective tax rate and $40 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 $12 million for income tax matters at March 31, 2016. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $18 million in unrecognized tax benefits could occur within the next twelve months.
Loss per Share
Earnings Per Share [Text Block]
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, 2016 and 2015, diluted loss per share for each period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following items from diluted earnings per common share for the three months ended March 31, 2016 and 2015, because they were anti-dilutive (shares in thousands):
 
 
Three Months Ended March 31,
 
 
2016
 
2015
Share-based awards
 
4,468

 
8,947

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 $7 million and $9 million for the three months ended March 31, 2016 and 2015, 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, 2016 and 2015. At March 31, 2016, there was unrecognized compensation cost of $45 million related to restricted stock which is expected to be recognized over a weighted average period of 1.9 years. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards.
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2016, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
3,528,270

 
$
19.91

Granted
2,836,587

 
$
12.30

Forfeited
64,334

 
$
16.73

Vested
1,214,161

 
$
19.02

Nonvested — March 31, 2016
5,086,362

 
$
15.92


The total fair value of our restricted stock and restricted stock units that vested during the three months ended March 31, 2016 and 2015 was approximately $15 million and $32 million, respectively.
Liability Classified Share-Based Awards
During the first quarter of 2016, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2016 through December 31, 2018 compared with the TSR performance of the S&P 500 companies over the same period, as modified by the IPP Sector Modifier which may either increase or decrease the payout based on Calpine’s TSR within its IPP Peers. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $2 million for each of the three months ended March 31, 2016 and 2015.
A summary of our performance share unit activity for the three months ended March 31, 2016, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
517,906

 
$
23.36

Granted
627,957

 
$
14.81

Vested(1)
3,249

 
$
23.91

Nonvested — March 31, 2016
1,142,614

 
$
18.66


___________
(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 2015 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 issued a notice of violation for this event on April 24, 2015. The BAAQMD continues to reserve its rights to assert any penalty claims associated with this violation and RCEC continues to reserve 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. At March 31, 2016, our reportable segments were West (including geothermal), Texas and East (including Canada). We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in 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, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
424

 
$
532

 
$
659

 
$

 
$
1,615

Intersegment revenues
2

 
3

 
3

 
(8
)
 

Total operating revenues
$
426

 
$
535

 
$
662

 
$
(8
)
 
$
1,615

Commodity Margin
$
197

 
$
153

 
$
230

 
$

 
$
580

Add: Mark-to-market commodity activity, net and other(1)
46

 
(110
)
 
(21
)
 
(6
)
 
(91
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
91

 
86

 
84

 
(6
)
 
255

Depreciation and amortization expense
69

 
53

 
58

 

 
180

Sales, general and other administrative expense
10

 
16

 
12

 

 
38

Other operating expenses
8

 
2

 
10

 

 
20

(Income) from unconsolidated investments in power plants

 

 
(7
)
 

 
(7
)
Income (loss) from operations
65

 
(114
)
 
52

 

 
3

Interest expense, net of interest income
 
 
 
 
 
 
 
 
156

Other (income) expense, net
 
 
 
 
 
 
 
 
6

Loss before income taxes
 
 
 
 
 
 
 
 
$
(159
)

 
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
)
_________
(1)
Includes $(22) million and $(24) million of lease levelization and $27 million and $4 million of amortization expense for the three months ended March 31, 2016 and 2015, respectively.
Basis of Presentation and Summary of Significant Accounting Policies (Policies)
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, 2015, included in our 2015 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.
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 cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts 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, making these cash funds unavailable for general use. 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 and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.
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.
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 in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. 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 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.
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 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 only apply hedge accounting to our interest rate derivative instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate swaps designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on 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, environmental product and fuel oil 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, power, environmental product and fuel oil 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.
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.
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.
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 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. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In addition, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” in March 2016 which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. We are currently assessing the future impact the revenue recognition 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 consolidation 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 adopted Accounting Standards Update 2015-02 in the first quarter of 2016 which did not have 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. In August 2015, the FASB issued Accounting Standards Update 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” which allows an entity to present debt issuance costs associated with a line-of-credit arrangement as an asset regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The standards are effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and require retrospective adoption with early adoption permitted. We retrospectively adopted Accounting Standard Updates 2015-03 and 2015-15 in the first quarter of 2016 which resulted in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion on our Consolidated Condensed Balance Sheet at December 31, 2015.

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 adopted Accounting Standards Update 2015-05 in the first quarter of 2016 which did not have a material impact on our financial condition, results of operations or cash flows.

Inventory In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” This standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective 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.

Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified 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.

Stock-Based Compensation In March 2016, the FASB issued Accounting Standards Update 2016-09, “Improvements to Employee Share-Based Payment Accounting.” This standard applies to several aspects of accounting for stock-based compensation including the recognition of excess tax benefits and deficiencies and their related presentation in the statement of cash flows as well as accounting for forfeitures. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and allows for prospective, retrospective or modified retrospective adoption, depending on the area covered in the update, 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 as a result of adopting this standard.
Basis of Presentation and Summary of Significant Accounting Policies (Tables)
The table below represents the components of our restricted cash as of March 31, 2016 and December 31, 2015 (in millions):

 
March 31, 2016
 
December 31, 2015
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
29

 
$
7

 
$
36

 
$
28

 
$
8

 
$
36

Construction/major maintenance
45

 
7

 
52

 
50

 
2

 
52

Security/project/insurance
91

 
1

 
92

 
136

 

 
136

Other
2

 
2

 
4

 
2

 
2

 
4

Total
$
167

 
$
17

 
$
184

 
$
216

 
$
12

 
$
228

Property, Plant and Equipment, Net — At March 31, 2016 and December 31, 2015, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2016
 
December 31, 2015
 
Depreciable Lives
Buildings, machinery and equipment
$
16,685

 
$
16,294

 
3 – 46 Years
Geothermal properties
1,327

 
1,319

 
13 – 58 Years
Other
219

 
208

 
3 – 46 Years
 
18,231

 
17,821

 
 
Less: Accumulated depreciation
5,491

 
5,377

 
 
 
12,740

 
12,444

 
 
Land
121

 
120

 
 
Construction in progress
546

 
448

 
 
Property, plant and equipment, net
$
13,407

 
$
13,012

 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables)
At March 31, 2016 and December 31, 2015, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
March 31, 2016
 
March 31, 2016
 
December 31, 2015
Greenfield LP
50%
 
$
71

 
$
65

Whitby
50%
 
18

 
14

Total investments in power plants
 
 
$
89

 
$
79

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,
 
 
2016
 
2015
Greenfield LP
 
$
(4
)
 
$
(2
)
Whitby
 
(3
)
 
(3
)
Total
 
$
(7
)
 
$
(5
)

Debt (Tables)
Our debt at March 31, 2016 and December 31, 2015, was as follows (in millions):
 
March 31, 2016

December 31, 2015
Senior Unsecured Notes
$
3,408

 
$
3,406

First Lien Term Loans
3,271

 
3,277

First Lien Notes
1,790

 
1,789

Project financing, notes payable and other
1,665

 
1,715

CCFC Term Loans
1,562

 
1,565

Capital lease obligations
181

 
185

Subtotal
11,877

 
11,937

Less: Current maturities
205

 
221

Total long-term debt
$
11,672

 
$
11,716

The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
March 31, 2016
 
December 31, 2015
2023 Senior Unsecured Notes
$
1,235

 
$
1,235

2024 Senior Unsecured Notes
642

 
641

2025 Senior Unsecured Notes
1,531

 
1,530

Total Senior Unsecured Notes
$
3,408

 
$
3,406

The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2016
 
December 31, 2015
2019 First Lien Term Loan
$
794

 
$
795

2020 First Lien Term Loan
377

 
378

2022 First Lien Term Loan
1,568

 
1,571

2023 First Lien Term Loan
532

 
533

Total First Lien Term Loans
$
3,271

 
$
3,277

The amounts outstanding under our First Lien Notes are summarized in the table below (in millions):
 
March 31, 2016
 
December 31, 2015
2022 First Lien Notes
$
738

 
$
737

2023 First Lien Notes
568

 
568

2024 First Lien Notes
484

 
484

Total First Lien Notes
$
1,790

 
$
1,789

The table below represents amounts issued under our letter of credit facilities at March 31, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
 
December 31, 2015
Corporate Revolving Facility(1)
$
314

 
$
316

CDHI
262

 
241

Various project financing facilities
178

 
198

Total
$
754

 
$
755

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
The following table details the fair values and carrying values of our debt instruments at March 31, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
 
December 31, 2015
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
3,315

 
$
3,408

 
$
3,063

 
$
3,406

First Lien Term Loans
3,290

 
3,271

 
3,197

 
3,277

First Lien Notes
1,906

 
1,790

 
1,885

 
1,789

Project financing, notes payable and other(1)
1,619

 
1,574

 
1,653

 
1,608

CCFC Term Loans
1,544

 
1,562

 
1,494

 
1,565

Total
$
11,674

 
$
11,605

 
$
11,292

 
$
11,645

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

Assets and Liabilities with Recurring Fair Value Measurements (Tables)
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2016
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
376

 
$

 
$

 
$
376

Margin deposits
94

 

 

 
94

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,967

 

 

 
1,967

Commodity forward contracts(2)

 
250

 
55

 
305

Interest rate swaps

 
1

 

 
1

Total assets
$
2,437

 
$
251

 
$
55

 
$
2,743

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

 
$

 
$

 
$
22

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,874

 

 

 
1,874

Commodity forward contracts(2)

 
468

 
120

 
588

Interest rate swaps

 
98

 

 
98

Total liabilities
$
1,896

 
$
566

 
$
120

 
$
2,582

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2015
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,083

 
$

 
$

 
$
1,083

Margin deposits
89

 

 

 
89

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,736

 

 

 
1,736

Commodity forward contracts(2)

 
220

 
54

 
274

Interest rate swaps

 
1

 

 
1

Total assets
$
2,908

 
$
221

 
$
54

 
$
3,183

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
35

 
$

 
$

 
$
35

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,604

 

 

 
1,604

Commodity forward contracts(2)

 
413

 
100

 
513

Interest rate swaps

 
90

 

 
90

Total liabilities
$
1,639

 
$
503

 
$
100

 
$
2,242

___________
(1)
As of March 31, 2016 and December 31, 2015, we had cash equivalents of $216 million and $880 million included in cash and cash equivalents and $160 million and $203 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2016 and December 31, 2015:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
March 31, 2016
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(77
)
 
Discounted cash flow
 
Market price (per MWh)
 
$4.95 — $100.54/MWh
Power Congestion Products
 
$
12

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.33) — $10.38/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(54
)
 
Discounted cash flow
 
Market price (per MWh)
 
$6.72 — $83.25/MWh
Power Congestion Products
 
$
8

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.47) — $12.19/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,
 
 
2016
 
2015
Balance, beginning of period
 
$
(46
)
 
$
85

Realized and mark-to-market gains (losses):
 
 
 
 
Included in net loss:
 
 
 
 
Included in operating revenues(1)
 
(22
)
 
131

Included in fuel and purchased energy expense(2)
 
(14
)
 
3

Purchases and settlements:
 
 
 
 
Purchases
 
2

 
2

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

 
(1
)
Transfers out of level 3(5)
 
19

 
(7
)
Balance, end of period
 
$
(65
)
 
$
203

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
(36
)
 
$
134

___________
(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, 2016 and 2015.
(4)
There were no transfers out of level 2 into level 3 for the three months ended March 31, 2016. We had $1 million in losses transferred out of level 2 into level 3 for the three months ended March 31, 2015.
(5)
We had $(19) million in losses and $7 million in gains transferred out of level 3 into level 2 for the three months ended March 31, 2016 and 2015, respectively, due to changes in market liquidity in various power markets.
Derivative Instruments (Tables)
As of March 31, 2016 and December 31, 2015, 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, 2016
 
December 31, 2015
Power (MWh)
 
(49
)
 
(41
)
Natural gas (MMBtu)
 
1,065

 
996

Environmental credits (Tonnes)
 
17

 
8

Interest rate swaps
 
$
1,308

 
$
1,320

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, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,853

 
$

 
$
1,853

Long-term derivative assets
419

 
1

 
420

Total derivative assets
$
2,272

 
$
1

 
$
2,273

 
 
 
 
 
 
Current derivative liabilities
$
1,938

 
$
37

 
$
1,975

Long-term derivative liabilities
524

 
61

 
585

Total derivative liabilities
$
2,462

 
$
98

 
$
2,560

Net derivative assets (liabilities)
$
(190
)
 
$
(97
)
 
$
(287
)

 
December 31, 2015
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,698

 
$

 
$
1,698

Long-term derivative assets
312

 
1

 
313

Total derivative assets
$
2,010

 
$
1

 
$
2,011

 
 
 
 
 
 
Current derivative liabilities
$
1,697

 
$
37

 
$
1,734

Long-term derivative liabilities
420

 
53

 
473

Total derivative liabilities
$
2,117

 
$
90

 
$
2,207

Net derivative assets (liabilities)
$
(107
)
 
$
(89
)
 
$
(196
)
 
March 31, 2016
 
December 31, 2015
 
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
$
1

 
$
100

 
$
1

 
$
92

Total derivatives designated as cash flow hedging instruments
$
1

 
$
100

 
$
1

 
$
92

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
2,272

 
$
2,462

 
$
2,010

 
$
2,117

Interest rate swaps

 
(2
)
 

 
(2
)
Total derivatives not designated as hedging instruments
$
2,272

 
$
2,460

 
$
2,010

 
$
2,115

Total derivatives
$
2,273

 
$
2,560

 
$
2,011

 
$
2,207

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, 2016 and December 31, 2015 (in millions):
 
 
March 31, 2016
 
 
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
 
$
1,967

 
$
(1,874
)
 
$
(93
)
 
$

Commodity forward contracts
 
305

 
(230
)
 
(7
)
 
68

Interest rate swaps
 
1

 

 

 
1

Total derivative assets
 
$
2,273

 
$
(2,104
)
 
$
(100
)
 
$
69

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,874
)
 
$
1,874

 
$

 
$

Commodity forward contracts
 
(588
)
 
230

 
1

 
(357
)
Interest rate swaps
 
(98
)
 

 

 
(98
)
Total derivative (liabilities)
 
$
(2,560
)
 
$
2,104

 
$
1

 
$
(455
)
Net derivative assets (liabilities)
 
$
(287
)
 
$

 
$
(99
)
 
$
(386
)
 
 
December 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
 
$
1,736

 
$
(1,602
)
 
$
(134
)
 
$

Commodity forward contracts
 
274

 
(202
)
 
(3
)
 
69

Interest rate swaps
 
1

 

 

 
1

Total derivative assets
 
$
2,011

 
$
(1,804
)
 
$
(137
)
 
$
70

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,604
)
 
$
1,602

 
$
2

 
$

Commodity forward contracts
 
(513
)
 
202

 
3

 
(308
)
Interest rate swaps
 
(90
)
 

 

 
(90
)
Total derivative (liabilities)
 
$
(2,207
)
 
$
1,804

 
$
5

 
$
(398
)
Net derivative assets (liabilities)
 
$
(196
)
 
$

 
$
(132
)
 
$
(328
)
____________
(1)
Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral.
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,
 
 
2016
 
2015
Realized gain (loss)(1)(2)
 
 
 
 
Commodity derivative instruments
 
$
118

 
$
59

Total realized gain (loss)
 
$
118

 
$
59

 
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
 
Commodity derivative instruments
 
$
(95
)
 
$
70

Interest rate swaps
 
1

 
1

Total mark-to-market gain (loss)
 
$
(94
)
 
$
71

Total activity, net
 
$
24

 
$
130

___________
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
Includes amortization of acquisition date fair value of derivative activity related to the acquisition of Champion Energy.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
 
Three Months Ended March 31,
 
 
2016
 
2015
Realized and mark-to-market gain (loss)
 
 
 
 
Derivatives contracts included in operating revenues(1)
 
$
204

 
$
119

Derivatives contracts included in fuel and purchased energy expense(1)
 
(181
)
 
10

Interest rate swaps included in interest expense
 
1

 
1

Total activity, net
 
$
24

 
$
130


___________
(1)
Does not include the realized value associated with derivative instruments that settle through physical delivery.
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)
 
2016
 
2015
 
2016
 
2015
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate swaps(1)(2)
$
(12
)
 
$
(6
)
 
$
(11
)
 
$
(12
)
 
Interest expense
____________
(1)
We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three months ended March 31, 2016 and 2015.
(2)
We recorded an income tax expense of nil for each of the three months ended March 31, 2016 and 2015, 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 $137 million and $127 million at March 31, 2016 and December 31, 2015, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $13 million and $11 million at March 31, 2016 and December 31, 2015, respectively.
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, 2016 and December 31, 2015 (in millions):
 
March 31, 2016
 
December 31, 2015
Margin deposits(1)
$
94

 
$
89

Natural gas and power prepayments
36

 
34

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
130

 
$
123

 
 
 
 
Letters of credit issued
$
629

 
$
600

First priority liens under power and natural gas agreements(3)
389

 
382

First priority liens under interest rate swap agreements
100

 
92

Total letters of credit and first priority liens with our counterparties
$
1,118

 
$
1,074

 
 
 
 
Margin deposits posted with us by our counterparties(1)(4)
$
22

 
$
35

Letters of credit posted with us by our counterparties
39

 
24

Total margin deposits and letters of credit posted with us by our counterparties
$
61

 
$
59

___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2016 and December 31, 2015, $116 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $14 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Includes $364 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at March 31, 2016 and December 31, 2015, respectively.
(4)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
Income Taxes Income Taxes (Tables)
Schedule of Components of Income Tax Expense (Benefit)
The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2016
 
2015
Income tax expense (benefit)
$
35

 
$
(1
)
Effective tax rate
(21
)%
 
9
%
Loss per Share (Tables)
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share
We excluded the following items from diluted earnings per common share for the three months ended March 31, 2016 and 2015, because they were anti-dilutive (shares in thousands):
 
 
Three Months Ended March 31,
 
 
2016
 
2015
Share-based awards
 
4,468

 
8,947

Stock-Based Compensation (Tables)
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2016, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
3,528,270

 
$
19.91

Granted
2,836,587

 
$
12.30

Forfeited
64,334

 
$
16.73

Vested
1,214,161

 
$
19.02

Nonvested — March 31, 2016
5,086,362

 
$
15.92

A summary of our performance share unit activity for the three months ended March 31, 2016, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
517,906

 
$
23.36

Granted
627,957

 
$
14.81

Vested(1)
3,249

 
$
23.91

Nonvested — March 31, 2016
1,142,614

 
$
18.66


___________
(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.
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, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
424

 
$
532

 
$
659

 
$

 
$
1,615

Intersegment revenues
2

 
3

 
3

 
(8
)
 

Total operating revenues
$
426

 
$
535

 
$
662

 
$
(8
)
 
$
1,615

Commodity Margin
$
197

 
$
153

 
$
230

 
$

 
$
580

Add: Mark-to-market commodity activity, net and other(1)
46

 
(110
)
 
(21
)
 
(6
)
 
(91
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
91

 
86

 
84

 
(6
)
 
255

Depreciation and amortization expense
69

 
53

 
58

 

 
180

Sales, general and other administrative expense
10

 
16

 
12

 

 
38

Other operating expenses
8

 
2

 
10

 

 
20

(Income) from unconsolidated investments in power plants

 

 
(7
)
 

 
(7
)
Income (loss) from operations
65

 
(114
)
 
52

 

 
3

Interest expense, net of interest income
 
 
 
 
 
 
 
 
156

Other (income) expense, net
 
 
 
 
 
 
 
 
6

Loss before income taxes
 
 
 
 
 
 
 
 
$
(159
)

 
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
)
_________
(1)
Includes $(22) million and $(24) million of lease levelization and $27 million and $4 million of amortization expense for the three months ended March 31, 2016 and 2015, respectively.
Basis of Presentation and Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Accounting Policies [Line Items]
 
 
 
Prior Period Reclassification Adjustment
 
 
$ 152 
Current
167 
 
216 
Non-current
17 
 
12 
Total
184 
 
228 
Interest costs capitalized
 
Debt service
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
29 
 
28 
Non-current
 
Total
36 
 
36 
Construction major maintenance
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
45 
 
50 
Non-current
 
Total
52 
 
52 
Security project insurance
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
91 
 
136 
Non-current
 
Total
92 
 
136 
Other
 
 
 
Accounting Policies [Line Items]
 
 
 
Current
 
Non-current
 
Total
$ 4 
 
$ 4 
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
58 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
46 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
46 years 
 
 
Basis of Presentation and Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Property, Plant and Equipment [Line Items]
 
 
Buildings, machinery and equipment
$ 16,685 
$ 16,294 
Geothermal properties
1,327 
1,319 
Other
219 
208 
Property, plant and equipment, gross
18,231 
17,821 
Less: Accumulated depreciation
5,491 
5,377 
Property, plant and equipment, gross, less accumulated depreciation, depletion and amortization
12,740 
12,444 
Land
121 
120 
Construction in progress
546 
448 
Property, plant and equipment, net
$ 13,407 
$ 13,012 
Acquisition (Details) (USD $)
In Millions, unless otherwise specified
Feb. 5, 2016
Granite Ridge Energy Center [Member]
MW
Oct. 1, 2015
Crane Champion Holdco, LLC [Member]
Oct. 1, 2015
EDF Trading North America, LLC [Member]
Oct. 1, 2015
Champion Energy Marketing, LLC [Member]
Apr. 1, 2016
South Point Energy Center [Member]
MW
Business Acquisition [Line Items]
 
 
 
 
 
Ownership percentage of acquiree
 
75.00% 
25.00% 
 
 
Business combination, recognized identifiable assets acquired and liabilities assumed, net
$ 500 
 
 
$ 240 
 
Power generation capacity
745 
 
 
 
 
Summer Peaking Capacity
695 
 
 
 
504 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
 
 
Equity method investments
$ 89 
$ 79 
Greenfield [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity method investments
71 
65 
Equity method investment, ownership percentage
50.00% 
 
Whitby [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity method investments
$ 18 
$ 14 
Equity method investment, ownership percentage
50.00% 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Income from Unconsolidated Investments 10-Q) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
(Income) from unconsolidated investments in power plants
$ (7)
$ (5)
Greenfield [Member]
 
 
(Income) from unconsolidated investments in power plants
(4)
(2)
Whitby [Member]
 
 
(Income) from unconsolidated investments in power plants
$ (3)
$ (3)
Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Variable Interest Entity [Line Items]
 
 
 
Variable interest entity, financial or other support, amount
$ 0 
$ 0 
 
Equity method investment, summarized financial information, debt
284 
 
269 
Prorata share of equity method investment, summarized financial information, debt
142 
 
135 
Greenfield [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Power generation capacity
1,038 
 
 
Equity method investment, ownership percentage
50.00% 
 
 
Distribution from equity method investee
 
Whitby [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Power generation capacity
50 
 
 
Equity method investment, ownership percentage
50.00% 
 
 
Distribution from equity method investee
$ 0 
$ 0 
 
Variable Interest Entity, Primary Beneficiary [Member]
 
 
 
Variable Interest Entity [Line Items]
 
 
 
Power generation capacity
10,266 
 
10,266 
Debt (Debt) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
$ 11,877 
$ 11,937 
Debt, Current
205 
221 
Long-term Debt, Excluding Current Maturities
11,672 
11,716 
Unsecured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
3,408 
3,406 
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
3,271 
3,277 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
1,790 
1,789 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
1,665 
1,715 
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
1,562 
1,565 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
$ 181 
$ 185 
Debt Senior Unsecured Notes (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,674 
$ 11,292 
Senior Unsecured Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,235 
1,235 
Senior Unsecured Notes 2024 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
642 
641 
Senior Unsecured Notes 2025 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,531 
1,530 
Unsecured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 3,408 
$ 3,406 
Debt (First Lien Term Loans) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,674 
$ 11,292 
First Lien Term Loan 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
794 
795 
2020 First Lien Term Loan [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
377 
378 
2022 First Lien Term Loan [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,568 
1,571 
2023 First Lien Term Loan [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
532 
533 
First Lien Term Loans [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 3,271 
$ 3,277 
Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,674 
$ 11,292 
2022 First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
738 
737 
First Lien Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
568 
568 
2024 First Lien Notes [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
484 
484 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 1,790 
$ 1,789 
Debt (Letter of Credit) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 754 
$ 755 
Corporate Revolving Credit Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
314 1
316 1
CDH [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
262 
241 
Various Project Financing Facilities [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 178 
$ 198 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
$ 11,674 
$ 11,292 
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,408 
3,406 
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,271 
3,277 
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,790 
1,789 
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
11,605 
11,645 
Reported Value Measurement [Member] |
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,408 
3,406 
Reported Value Measurement [Member] |
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,271 
3,277 
Reported Value Measurement [Member] |
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,790 
1,789 
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
1,574 1
1,608 1
Reported Value Measurement [Member] |
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,562 
1,565 
Fair Value, Inputs, Level 2 [Member] |
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,315 
3,063 
Fair Value, Inputs, Level 2 [Member] |
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,290 
3,197 
Fair Value, Inputs, Level 2 [Member] |
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,906 
1,885 
Fair Value, Inputs, Level 2 [Member] |
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,544 
1,494 
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
$ 1,619 1
$ 1,653 1
Debt (Debt Textuals) (Details) (USD $)
12 Months Ended 3 Months Ended
Dec. 31, 2015
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Corporate Revolving Credit Facility [Member]
Feb. 8, 2016
Corporate Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
 
 
 
 
 
Line of Credit Facility, Increase (Decrease), Net
 
 
 
$ 178,000,000 
 
Line of Credit Facility, Maximum Borrowing Capacity
 
 
 
 
1,678,000,000 
Future line of credit facility maximum borrowing capacity on June 27, 2018
 
 
 
1,520,000,000 
 
Increase in Letter of Credit Sublimit
 
 
 
 
250,000,000 
Total Letter of Credit Sublimit
 
 
 
 
1,000,000,000 
Extension of Line of Credit Revolver
 
 
 
2 years 
 
Debt Instruments [Abstract]
 
 
 
 
 
Prior Period Reclassification Adjustment
$ 152,000,000 
 
 
 
 
Debt Instrument, Interest Rate, Effective Percentage
 
5.50% 
5.70% 
 
 
Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 376 1
$ 1,083 1
Margin deposits
94 2
89 2
Commodity futures contracts
1,967 
1,736 
Commodity forward contracts
305 3
274 3
Interest Rate Derivative Assets, Fair Value
Total assets
2,743 
3,183 
Margin deposits held by us posted by our counterparties
22 2 4
35 2 4
Commodity futures contracts
1,874 
1,604 
Commodity forward contracts
588 3
513 3
Interest Rate Derivative Liabilities At Fair Value
98 
90 
Liabilities, Fair Value Disclosure
2,582 
2,242 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
376 1
1,083 1
Margin deposits
94 
89 
Commodity futures contracts
1,967 
1,736 
Commodity forward contracts
3
3
Interest Rate Derivative Assets, Fair Value
Total assets
2,437 
2,908 
Margin deposits held by us posted by our counterparties
22 
35 
Commodity futures contracts
1,874 
1,604 
Commodity forward contracts
3
3
Interest Rate Derivative Liabilities At Fair Value
Liabilities, Fair Value Disclosure
1,896 
1,639 
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1
1
Margin deposits
Commodity futures contracts
Commodity forward contracts
250 3
220 3
Interest Rate Derivative Assets, Fair Value
Total assets
251 
221 
Margin deposits held by us posted by our counterparties
Commodity futures contracts
Commodity forward contracts
468 3
413 3
Interest Rate Derivative Liabilities At Fair Value
98 
90 
Liabilities, Fair Value Disclosure
566 
503 
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1
1
Margin deposits
Commodity futures contracts
Commodity forward contracts
55 3
54 3
Interest Rate Derivative Assets, Fair Value
Total assets
55 
54 
Margin deposits held by us posted by our counterparties
Commodity futures contracts
Commodity forward contracts
120 3
100 3
Interest Rate Derivative Liabilities At Fair Value
Liabilities, Fair Value Disclosure
$ 120 
$ 100 
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) (USD $)
Mar. 31, 2016
Dec. 31, 2015
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
$ (287,000,000)
$ (196,000,000)
Power Contracts [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
(77,000,000)
(54,000,000)
Power Contracts [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
4.95 
6.72 
Power Contracts [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
100.54 
83.25 
Natural Gas [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
 
   
Natural Gas [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
 
   
Power Congestion Products [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
12,000,000 
8,000,000 
Power Congestion Products [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
(11.33)
(11.47)
Power Congestion Products [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
$ 10.38 
$ 12.19 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Dec. 31, 2015
Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Balance, beginning of period
$ (46)
$ 85 
 
 
Included in net income:
 
 
 
 
Included in operating revenues
(22)1
131 1
 
 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense
(14)2
2
 
 
Purchases, issuances and settlements:
 
 
 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases
 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements
(4)
(10)
 
 
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount
 
 
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount
 
 
Transfers into level 3
3 4
3 4
 
 
Transfers out of Level 3
19 4 5
(7)4 5
 
 
Balance, end of period
(65)
203 
 
 
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)
(36)
134 
 
 
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
 
 
 
 
Cash and Cash Equivalents, at Carrying Value
244 
796 
906 
717 
Restricted Cash and Cash Equivalents
184 
 
228 
 
Fair Value Measurement [Domain]
 
 
 
 
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
 
 
 
 
Cash and Cash Equivalents, at Carrying Value
216 
 
880 
 
Restricted Cash and Cash Equivalents
$ 160 
 
$ 203 
 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended
Mar. 31, 2016
Power [Member]
MWh
Dec. 31, 2014
Power [Member]
MWh
Mar. 31, 2016
Natural Gas [Member]
MMBTU
Dec. 31, 2014
Natural Gas [Member]
MMBTU
Mar. 31, 2016
Environmental Credits [Member]
t
Dec. 31, 2014
Environmental Credits [Member]
t
Mar. 31, 2016
Interest Rate Swap [Member]
Dec. 31, 2015
Interest Rate Swap [Member]
Derivative [Line Items]
 
 
 
 
 
 
 
 
Derivative, Nonmonetary Notional Amount, Energy Measure
(49)
(41)
1,065 
996 
 
 
 
 
Derivative, Nonmonetary Notional Amount, Mass
 
 
 
 
17 
 
 
Derivative, Notional Amount
 
 
 
 
 
 
$ 1,308 
$ 1,320 
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
$ 1,853 
$ 1,698 
Long-term derivative assets
420 
313 
Total derivative assets
2,273 
2,011 
Derivative liabilities, current
1,975 
1,734 
Long-term derivative liabilities
585 
473 
Total derivative liabilities
2,560 
2,207 
Derivative, Fair Value, Net
(287)
(196)
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
Total derivative liabilities
100 
92 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
2,272 
2,010 
Total derivative liabilities
2,460 
2,115 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
Derivative Assets, Noncurrent
Total derivative assets
Current derivative liabilities
37 
37 
Derivative Liabilities, Noncurrent
61 
53 
Total derivative liabilities
98 
90 
Derivative, Fair Value, Net
(97)
(89)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
Total derivative liabilities
100 
92 
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
Total derivative liabilities
(2)
(2)
Energy Related Derivative [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
1,853 
1,698 
Derivative Assets, Noncurrent
419 
312 
Total derivative assets
2,272 
2,010 
Current derivative liabilities
1,938 
1,697 
Derivative Liabilities, Noncurrent
524 
420 
Total derivative liabilities
2,462 
2,117 
Derivative, Fair Value, Net
(190)
(107)
Energy Related Derivative [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
2,272 
2,010 
Total derivative liabilities
$ 2,462 
$ 2,117 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Power contracts included in operating revenues
$ 1,615 
$ 1,646 
Natural gas contracts included in fuel and purchased energy expense
1,126 
1,010 
Interest expense
157 
154 
Gain (Loss) on Derivative Instruments, Net, Pretax
24 
130 
Gain (Loss) on Sale of Derivatives
118 1 2
59 1 2
Mark-to-market gain (loss)
(94)3
71 3
Power [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Power contracts included in operating revenues
204 1
119 1
Interest Rate Swap [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Interest expense
Mark-to-market gain (loss)
3
3
Energy Related Derivative [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Gain (Loss) on Sale of Derivatives
118 1 2
59 1 2
Mark-to-market gain (loss)
(95)3
70 3
Natural Gas [Member]
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
Natural gas contracts included in fuel and purchased energy expense
$ (181)1
$ 10 1
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Interest expense
$ 157 
$ 154 
Interest Rate Swap [Member]
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
Interest expense
$ 1 
$ 1 
Derivative Instruments (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Mar. 31, 2016
Parent [Member]
Dec. 31, 2015
Parent [Member]
Mar. 31, 2016
Noncontrolling Interest [Member]
Dec. 31, 2015
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
 
 
137 
127 
13 
11 
Summary of Derivative Instruments [Abstract]
 
 
 
 
 
 
Maximum length of time hedging using interest rate derivative instruments
8 years 
 
 
 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
57 
 
 
 
 
 
Collateral Already Posted, Aggregate Fair Value
 
 
 
 
 
Additional Collateral, Aggregate Fair Value
14 
 
 
 
 
 
Cash Flow Hedge (Gain) Loss to be Reclassified within Twelve Months
$ 41 
 
 
 
 
 
Derivative Instruments (Detail 5) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 2,273 
$ 2,011 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(2,104)
(1,804)
Derivative, Collateral, Obligation to Return Cash
(100)1
(137)1
Derivative Liability, Fair Value, Gross Liability
(2,560)
(2,207)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
2,104 
1,804 
Derivative, Collateral, Right to Reclaim Cash
1
1
Derivative, Fair Value, Net
(287)
(196)
Derivative Fair Value, Amount Not Offset Against Collateral, Net
Margin/Cash (Received) Posted Subject to Master Netting Arrangement
(99)1
(132)1
Derivative Asset, Fair Value, Amount Offset Against Collateral
69 
70 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(455)
(398)
Derivative, Fair Value, Amount Offset Against Collateral, Net
(386)
(328)
Commodity Exchange Traded Futures and Swaps Contracts [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
1,967 
1,736 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(1,874)
(1,602)
Derivative, Collateral, Obligation to Return Cash
(93)1
(134)1
Derivative Liability, Fair Value, Gross Liability
(1,874)
(1,604)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
1,874 
1,602 
Derivative, Collateral, Right to Reclaim Cash
1
1
Derivative Asset, Fair Value, Amount Offset Against Collateral
Derivative Liability, Fair Value, Amount Offset Against Collateral
Commodity Forward Contract [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
305 
274 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(230)
(202)
Derivative, Collateral, Obligation to Return Cash
(7)1
(3)1
Derivative Liability, Fair Value, Gross Liability
(588)
(513)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
230 
202 
Derivative, Collateral, Right to Reclaim Cash
1
1
Derivative Asset, Fair Value, Amount Offset Against Collateral
68 
69 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(357)
(308)
Interest Rate Swap [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
Derivative, Collateral, Obligation to Return Cash
1
1
Derivative Liability, Fair Value, Gross Liability
(98)
(90)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
Derivative, Collateral, Right to Reclaim Cash
1
1
Derivative, Fair Value, Net
(97)
(89)
Derivative Asset, Fair Value, Amount Offset Against Collateral
Derivative Liability, Fair Value, Amount Offset Against Collateral
$ (98)
$ (90)
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2016
Dec. 31, 2015
Financial Instruments Owned and Pledged as Collateral [Line Items]
 
 
Margin deposits
$ 94 1
$ 89 1
Natural gas and power prepayments
36 
34 
Total margin deposits and natural gas and power prepayments with our counterparties
130 2
123 2
Letters of credit issued
629 
600 
First priority liens under power and natural gas agreements
389 3
382 3
First priority liens under interest rate swap agreements
100 
92 
Total letters of credit and first priority liens with our counterparties
1,118 
1,074 
Margin deposits held by us posted by our counterparties
22 1 4
35 1 4
Letters of credit posted with us by our counterparties
39 
24 
Total margin deposits and letters of credit posted with us by our counterparties
61 
59 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
14 
22 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
116 
101 
Champion Energy [Member]
 
 
Financial Instruments Owned and Pledged as Collateral [Line Items]
 
 
First priority liens under power and natural gas agreements
$ 364 
$ 345 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Income Tax Contingency [Line Items]
 
 
Income tax (expense) benefit
$ (35)
$ 1 
Effective Income Tax Rate, Continuing Operations
(21.00%)
9.00% 
Income Tax Uncertainties [Abstract]
 
 
Unrecognized Tax Benefits
57 
 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
17 
 
Unrecognized Tax Benefit Related to Deferred Tax Asset
40 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
12 
 
Minimum [Member]
 
 
Income Tax Contingency [Line Items]
 
 
Decrease in Unrecognized Tax Benefits is Reasonably Possible
 
Maximum [Member]
 
 
Income Tax Contingency [Line Items]
 
 
Decrease in Unrecognized Tax Benefits is Reasonably Possible
$ 18 
 
Loss per Share (Details)
In Thousands, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Earnings Per Share [Abstract]
 
 
Share-based awards
4,468 
8,947 
Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) (Restricted Stock [Member], USD $)
3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
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
5,086,362 
3,528,270 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 15.92 
$ 19.91 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
2,836,587 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 12.30 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
64,334 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value
$ 16.73 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
1,214,161 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 19.02 
 
Stock-Based Compensation (Stock Based Compensation Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
Allocated Share-based Compensation Expense
$ 7 
$ 9 
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards
 
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
45 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
1 year 11 months 8 days 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
$ 15 
$ 32 
Stock-Based Compensation Liability Based Stock Compensation (Details) (Performance Shares [Member], USD $)
3 Months Ended
Mar. 31, 2016
Dec. 31, 2015
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
1,142,614 
517,906 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 18.66 
$ 23.36 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
627,957 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 14.81 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
3,249 1
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 23.91 
 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2016
Mar. 31, 2015
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
$ 1,615 
$ 1,646 
Commodity Margin
580 
535 
Add: Mark-to-market commodity activity, net and other
(91)1
101 1
Plant operating expense
255 
260 
Depreciation and amortization expense
180 
158 
Sales, general and other administrative expense
38 
37 
Other operating expenses
20 
20 
(Income) loss from unconsolidated investments in power plants
(7)
(5)
Income from operations
166 
Interest expense, net of interest income
156 
153 
Other (income) expense, net
Debt Extinguishment Costs and Other (Income) Expense, Net
 
21 
Loss before income taxes
(159)
(8)
Lease levelization
(22)
(24)
Amortization of Intangible Assets
27 
West [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
426 
517 
Commodity Margin
197 
218 
Add: Mark-to-market commodity activity, net and other
46 1
119 1
Plant operating expense
91 
106 
Depreciation and amortization expense
69 
67 
Sales, general and other administrative expense
10 
10 
Other operating expenses
10 
(Income) loss from unconsolidated investments in power plants
Income from operations
65 
144 
Texas [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
535 
584 
Commodity Margin
153 
149 
Add: Mark-to-market commodity activity, net and other
(110)1
41 1
Plant operating expense
86 
89 
Depreciation and amortization expense
53 
49 
Sales, general and other administrative expense
16 
17 
Other operating expenses
(Income) loss from unconsolidated investments in power plants
Income from operations
(114)
33 
East [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
662 
552 
Commodity Margin
230 
168 
Add: Mark-to-market commodity activity, net and other
(21)1
(52)1
Plant operating expense
84 
72 
Depreciation and amortization expense
58 
42 
Sales, general and other administrative expense
12 
10 
Other operating expenses
10 
(Income) loss from unconsolidated investments in power plants
(7)
(5)
Income from operations
52 
(11)
Consolidation, Eliminations [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
(8)
(7)
Commodity Margin
Add: Mark-to-market commodity activity, net and other
(6)1
(7)1
Plant operating expense
(6)
(7)
Depreciation and amortization expense
Sales, general and other administrative expense
Other operating expenses
(Income) loss from unconsolidated investments in power plants
Income from operations
Operating Segments [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
1,615 
1,646 
Operating Segments [Member] |
West [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
424 
515 
Operating Segments [Member] |
Texas [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
532 
581 
Operating Segments [Member] |
East [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
659 
550 
Operating Segments [Member] |
Consolidation, Eliminations [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
Intersegment Eliminations [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
Intersegment Eliminations [Member] |
West [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
Intersegment Eliminations [Member] |
Texas [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
Intersegment Eliminations [Member] |
East [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
Intersegment Eliminations [Member] |
Consolidation, Eliminations [Member]
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
Operating revenues
$ (8)
$ (7)