CALPINE CORP, 10-Q filed on 7/29/2016
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2016
Jul. 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
Jun. 30, 2016 
 
Document Fiscal Year Focus
2016 
 
Document Fiscal Period Focus
Q2 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
359,139,572 
Consolidated Condensed Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Operating revenues:
 
 
 
 
Commodity revenue
$ 1,551 
$ 1,407 
$ 3,136 
$ 3,045 
Mark-to-market gain (loss)
(391)
31 
(366)
34 
Other revenue
Operating revenues
1,164 
1,442 
2,779 
3,088 
Operating expenses:
 
 
 
 
Commodity expense
897 
734 
1,903 
1,811 
Mark-to-market (gain) loss
(355)
32 
(235)
(35)
Fuel and purchased energy expense
542 
766 
1,668 
1,776 
Plant operating expense
271 
272 
526 
532 
Depreciation and amortization expense
162 
160 
342 
318 
Sales, general and other administrative expense
35 
30 
73 
67 
Other operating expenses
17 
20 
37 
40 
Total operating expenses
1,027 
1,248 
2,646 
2,733 
(Income) from unconsolidated investments in power plants
(3)
(7)
(10)
(12)
Income from operations
140 
201 
143 
367 
Interest expense
157 
158 
314 
312 
Interest (income)
(1)
(1)
(2)
(2)
Debt modification and extinguishment costs
15 
13 
15 
32 
Other (income) expense, net
13 
Income (loss) before income taxes
(38)
26 
(197)
18 
Income tax expense (benefit)
(14)
21 
Net income (loss)
(24)
21 
(218)
14 
Net income attributable to the noncontrolling interest
(5)
(2)
(9)
(5)
Net income (loss) attributable to Calpine
$ (29)
$ 19 
$ (227)
$ 9 
Basic earnings (loss) per common share attributable to Calpine:
 
 
 
 
Weighted average number of shares outstanding, basic
354,066 
366,975 
353,784 
369,938 
Earnings per share, basic
$ (0.08)
$ 0.05 
$ (0.64)
$ 0.02 
Weighted Average Number of Shares Outstanding, Diluted
354,066 
369,946 
353,784 
373,404 
Earnings Per Share, Diluted
$ (0.08)
$ 0.05 
$ (0.64)
$ 0.02 
Consolidated Condensed Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net income (loss)
$ (24)
$ 21 
$ (218)
$ 14 
Cash flow hedging activities:
 
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
(17)
(40)
(16)
Reclassification adjustment for loss on cash flow hedges realized in net income (loss)
11 
12 
22 
24 
Foreign currency translation gain (loss)
12 
(8)
Income tax expense
Other comprehensive income (loss)
(6)
18 
(6)
Comprehensive income (loss)
(30)
39 
(224)
14 
Comprehensive (income) attributable to the noncontrolling interest
(5)
(4)
(7)
(6)
Comprehensive income (loss) attributable to Calpine
$ (35)
$ 35 
$ (231)
$ 8 
Consolidated Condensed Balance Sheets (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Current assets:
 
 
Cash and cash equivalents ($69 and $118 attributable to VIEs)
$ 215 
$ 906 
Accounts receivable, net of allowance of $4 and $2
720 
644 
Inventories
522 
475 
Margin deposits and other prepaid expense
193 
137 
Restricted cash, current ($96 and $132 attributable to VIEs)
148 
216 
Derivative assets, current
1,231 
1,698 
Current assets held for sale
206 
Other current assets
53 
19 
Total current assets
3,288 
4,095 
Property, plant and equipment, net ($3,993 and $4,062 attributable to VIEs)
13,341 
13,012 
Restricted cash, net of current portion ($20 and $11 attributable to VIEs)
20 
12 
Investments in power plants
74 
79 
Long-term derivative assets
369 
313 
Assets Held-for-sale, Not Part of Disposal Group
130 
Other assets ($115 and $119 attributable to VIEs)
887 
1,040 
Total assets
17,979 
18,681 
Current liabilities:
 
 
Accounts payable
531 
552 
Accrued interest payable
130 
129 
Debt, current portion ($164 and $166 attributable to VIEs)
197 
221 
Derivative liabilities, current
1,360 
1,734 
Other current liabilities
355 
412 
Total current liabilities
2,573 
3,048 
Debt, net of current portion ($3,031 and $3,096 attributable to VIEs)
11,644 
11,716 
Long-term derivative liabilities
512 
473 
Other long-term liabilities
298 
277 
Total liabilities
15,027 
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, 359,662,911 and 356,755,747 shares issued, respectively, and 359,139,948 and 356,662,004 shares outstanding, respectively
Treasury stock, at cost, 522,963 and 93,743 shares, respectively
(7)
(1)
Additional paid-in capital
9,611 
9,594 
Accumulated deficit
(6,532)
(6,305)
Accumulated other comprehensive loss
(183)
(179)
Total Calpine stockholders’ equity
2,889 
3,109 
Noncontrolling interest
63 
58 
Total stockholders’ equity
2,952 
3,167 
Total liabilities and stockholders’ equity
$ 17,979 
$ 18,681 
Consolidated Condensed Balance Sheets (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Cash and cash equivalents ($69 and $118 attributable to VIEs)
$ 215 
$ 906 
Accounts receivable, net of allowance of $4 and $2
Restricted cash, current ($96 and $132 attributable to VIEs)
148 
216 
Property, plant and equipment, net ($3,993 and $4,062 attributable to VIEs)
13,341 
13,012 
Restricted cash, net of current portion ($20 and $11 attributable to VIEs)
20 
12 
Other assets ($115 and $119 attributable to VIEs)
887 
1,040 
Debt, current portion ($164 and $166 attributable to VIEs)
197 
221 
Debt, net of current portion ($3,031 and $3,096 attributable to VIEs)
11,644 
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
359,662,911 
356,755,747 
Common Stock, Shares, Outstanding
359,139,948 
356,662,004 
Treasury Stock, Shares
522,963 
93,743 
Variable Interest Entity, Primary Beneficiary [Member]
 
 
Cash and cash equivalents ($69 and $118 attributable to VIEs)
69 
118 
Restricted cash, current ($96 and $132 attributable to VIEs)
96 
132 
Property, plant and equipment, net ($3,993 and $4,062 attributable to VIEs)
3,993 
4,062 
Restricted cash, net of current portion ($20 and $11 attributable to VIEs)
20 
11 
Other assets ($115 and $119 attributable to VIEs)
115 
119 
Debt, current portion ($164 and $166 attributable to VIEs)
164 
166 
Debt, net of current portion ($3,031 and $3,096 attributable to VIEs)
$ 3,031 
$ 3,143 
Consolidated Condensed Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Cash flows from operating activities:
 
 
Net income (loss)
$ (218)
$ 14 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization(1)
459 1
342 1
Non Cash Gains Losses On Extinguishment Of Debt
15 
Income taxes
11 
Mark-to-market activity, net
130 2
(70)2
(Income) from unconsolidated investments in power plants
(10)
(12)
Return on consolidated investments in power plants
18 
13 
Stock-based compensation expense
17 
12 
Other Noncash Income (Expense)
(1)
Change in operating assets and liabilities, net of effect of acquisition:
 
 
Accounts receivable
(78)
29 
Derivative instruments, net
(69)
(36)
Other assets
(116)
(118)
Accounts payable and accrued expenses
(90)
(205)
Other liabilities
52 
45 
Net cash provided by operating activities
120 
19 
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(223)
(279)
Purchase of Granite Ridge Energy Center
(526)
Decrease in restricted cash
60 
34 
Other
13 
(1)
Net cash used in investing activities
(676)
(246)
Cash flows from financing activities:
 
 
Borrowings under CCFC Term Loans and First Lien Term Loans
556 
1,592 
Repayment of CCFC Term Loans and First Lien Term Loans
(1,209)
(1,613)
Borrowings under Senior Unsecured Notes
650 
Borrowings under First Lien Notes
625 
Repurchase of First Lien Notes
(147)
Repayments of project financing, notes payable and other
(81)
(85)
Financing costs
(26)
(17)
Stock repurchases
(454)
Proceeds from (Payments for) Other Financing Activities
Net cash used in financing activities
(135)
(68)
Net decrease in cash and cash equivalents
(691)
(295)
Cash and cash equivalents, beginning of period
906 
717 
Cash and cash equivalents, end of period
215 
422 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
289 
322 
Income taxes
17 
Supplemental disclosure of non-cash investing and financing activities:
 
 
Change in capital expenditures included in accounts payable
24 
(20)
Capital Lease Obligations Incurred
$ 0 
$ 9 
Basis of Presentation and Summary of Significant Accounting Policies
Summary of significant accounting policies
Basis of Presentation and Summary of Significant Accounting Policies
We are a 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 June 30, 2016 and December 31, 2015 (in millions):

 
June 30, 2016
 
December 31, 2015
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
34

 
$
8

 
$
42

 
$
28

 
$
8

 
$
36

Construction/major maintenance
36

 
9

 
45

 
50

 
2

 
52

Security/project/insurance
75

 
2

 
77

 
136

 

 
136

Other
3

 
1

 
4

 
2

 
2

 
4

Total
$
148

 
$
20

 
$
168

 
$
216

 
$
12

 
$
228


Business Interruption Proceeds — We record business interruption insurance proceeds when they are realizable and recorded approximately $8 million of business interruption proceeds in operating revenues during the three and six months ended June 30, 2016. We did not record any business interruption proceeds during the three and six months ended June 30, 2015.
Property, Plant and Equipment, Net — At June 30, 2016 and December 31, 2015, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
June 30, 2016
 
December 31, 2015
 
Depreciable Lives
Buildings, machinery and equipment
$
16,712

 
$
16,294

 
3 – 46 Years
Geothermal properties
1,368

 
1,319

 
13 – 58 Years
Other
230

 
208

 
3 – 46 Years
 
18,310

 
17,821

 
 
Less: Accumulated depreciation
5,652

 
5,377

 
 
 
12,658

 
12,444

 
 
Land
121

 
120

 
 
Construction in progress
562

 
448

 
 
Property, plant and equipment, net
$
13,341

 
$
13,012

 
 
Capitalized Interest — The total amount of interest capitalized was $5 million and $4 million for the three months ended June 30, 2016 and 2015, respectively, and $9 million during each of the six months ended June 30, 2016 and 2015.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
We did not record any material impairments during the three and six months ended June 30, 2016 and 2015.
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 March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We are currently assessing the potential 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 became effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period. 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 became effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period. 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 became effective for fiscal years beginning after December 15, 2015, including interim periods. 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 potential 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 standard, with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
Acquisition (Notes)
Mergers, acquisitions and dispositions disclosures
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 and six months ended June 30, 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 and six months ended June 30, 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 for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. 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 peaking capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration.
Sale of Osprey Energy Center
We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.
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 reported as current assets held for sale on our Consolidated Condensed Balance Sheet at June 30, 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 six months ended June 30, 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 June 30, 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 and six months ended June 30, 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 June 30, 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
June 30, 2016
 
June 30, 2016
 
December 31, 2015
Greenfield LP
50%
 
$
67

 
$
65

Whitby
50%
 
7

 
14

Total investments in power plants
 
 
$
74

 
$
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 June 30, 2016 and December 31, 2015, equity method investee debt was approximately $279 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 $139 million and $135 million at June 30, 2016 and December 31, 2015, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the three and six months ended June 30, 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 June 30,
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
Greenfield LP
 
$
(1
)
 
$
(4
)
 
$
(5
)
 
$
(6
)
Whitby
 
(2
)
 
(3
)
 
(5
)
 
(6
)
Total
 
$
(3
)
 
$
(7
)
 
$
(10
)
 
$
(12
)

Distributions from Greenfield LP were $5 million during each of the three and six months ended June 30, 2016, and nil during each of the three and six months ended June 30, 2015. Distributions from Whitby were $13 million during each of the three and six months ended June 30, 2016 and 2015.
Significant Unconsolidated Subsidiaries — Greenfield LP and Whitby met the criteria of significant unconsolidated subsidiaries for the six months ended June 30, 2015, based upon the relationship of our equity income from our investment to our consolidated net income before taxes. Aggregated summarized financial data for the six months ended June 30, 2016 and 2015 are set forth below (in millions):

Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
(Unaudited)

 
 
Six Months Ended June 30,
 
 
2016
 
2015
Revenues
 
$
75

 
$
98

Operating expenses
 
43

 
66

Income from operations
 
32

 
32

Interest expense, net of interest income
 
8

 
10

Other (income) expense, net
 
3

 
(1
)
Net income
 
$
21

 
$
23

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 June 30, 2016 and December 31, 2015, was as follows (in millions):
 
June 30, 2016

December 31, 2015
Senior Unsecured Notes
$
3,409

 
$
3,406

First Lien Term Loans
2,642

 
3,277

First Lien Notes
2,407

 
1,789

Project financing, notes payable and other
1,643

 
1,715

CCFC Term Loans
1,559

 
1,565

Capital lease obligations
181

 
185

Subtotal
11,841

 
11,937

Less: Current maturities
197

 
221

Total long-term debt
$
11,644

 
$
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 hedging instruments, decreased to 5.5% for the six months ended June 30, 2016, from 5.7% for the same period in 2015. The issuance of our New 2023 First Lien Term Loan in May 2016, our 2024 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 Term Loans and First Lien Notes 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):
 
June 30, 2016
 
December 31, 2015
2023 Senior Unsecured Notes
$
1,236

 
$
1,235

2024 Senior Unsecured Notes
642

 
641

2025 Senior Unsecured Notes
1,531

 
1,530

Total Senior Unsecured Notes
$
3,409

 
$
3,406


First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
 
June 30, 2016
 
December 31, 2015
2019 First Lien Term Loan
$

 
$
795

2020 First Lien Term Loan

 
378

2022 First Lien Term Loan
1,565

 
1,571

2023 First Lien Term Loan
531

 
533

New 2023 First Lien Term Loan
546

 

Total First Lien Term Loans
$
2,642

 
$
3,277


On May 31, 2016, we entered into a $562 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the New 2023 First Lien Term Loan credit agreement), plus an applicable margin of 2.00%, or (ii) LIBOR plus 3.00% per annum (with no LIBOR floor) and matures on May 31, 2023. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the New 2023 First Lien Term Loan, which is structured as original issue discount and recorded approximately $11 million in deferred financing costs during the three months ended June 30, 2016 related to the issuance of our New 2023 First Lien Term Loan. The New 2023 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and the First Lien Notes.
We used the proceeds from the New 2023 First Lien Term Loan and the 2026 First Lien Notes, discussed below, to repay the 2019 and 2020 First Lien Term Loans and recorded $15 million in debt extinguishment costs during the three months ended June 30, 2016 associated with the repayment.
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
 
June 30, 2016
 
December 31, 2015
2022 First Lien Notes
$
738

 
$
737

2023 First Lien Notes
569

 
568

2024 First Lien Notes
484

 
484

2026 First Lien Notes
616

 

Total First Lien Notes
$
2,407

 
$
1,789


On May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Our 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2016. Our 2026 First Lien Notes mature on June 1, 2026 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $9 million in deferred financing costs during the three months ended June 30, 2016 related to the issuance of our 2026 First Lien Notes.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
Corporate Revolving Facility(1)
$
304

 
$
316

CDHI
261

 
241

Various project financing facilities
212

 
198

Total
$
777

 
$
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 June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
3,357

 
$
3,409

 
$
3,063

 
$
3,406

First Lien Term Loans
2,662

 
2,642

 
3,197

 
3,277

First Lien Notes
2,531

 
2,407

 
1,885

 
1,789

Project financing, notes payable and other(1)
1,595

 
1,551

 
1,653

 
1,608

CCFC Term Loans
1,537

 
1,559

 
1,494

 
1,565

Total
$
11,682

 
$
11,568

 
$
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 hedging instruments. 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 hedging instruments 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.
For a definition of the different levels in the fair value hierarchy, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies — Fair Value Measurements” in our 2015 Form 10-K.
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 June 30, 2016 and December 31, 2015, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2016
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
383

 
$

 
$

 
$
383

Margin deposits
134

 

 

 
134

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,316

 

 

 
1,316

Commodity forward contracts(2)

 
232

 
43

 
275

Interest rate hedging instruments

 
9

 

 
9

Total assets
$
1,833

 
$
241

 
$
43

 
$
2,117

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
9

 
$

 
$

 
$
9

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,248

 

 

 
1,248

Commodity forward contracts(2)

 
422

 
106

 
528

Interest rate hedging instruments

 
96

 

 
96

Total liabilities
$
1,257

 
$
518

 
$
106

 
$
1,881

 
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)
$
1,134

 
$

 
$

 
$
1,134

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 hedging instruments

 
1

 

 
1

Total assets
$
2,959

 
$
221

 
$
54

 
$
3,234

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 hedging instruments

 
90

 

 
90

Total liabilities
$
1,639

 
$
503

 
$
100

 
$
2,242

___________
(1)
As of June 30, 2016 and December 31, 2015, we had cash equivalents of $215 million and $906 million included in cash and cash equivalents and $168 million and $228 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
At June 30, 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 June 30, 2016 and December 31, 2015:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
June 30, 2016
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(80
)
 
Discounted cash flow
 
Market price (per MWh)
 
$9.09 — $104.83/MWh
Power Congestion Products
 
$
17

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.47) — $11.76/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 June 30,
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
Balance, beginning of period
 
$
(65
)
 
$
203

 
$
(46
)
 
$
85

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
 
 
Included in net income (loss):
 
 
 
 
 
 
 
 
Included in operating revenues(1)
 
(174
)
 
45

 
(181
)
 
176

Included in fuel and purchased energy expense(2)
 
165

 

 
155

 
2

Purchases and settlements:
 
 
 
 
 
 
 
 
Purchases
 
4

 
2

 
5

 
4

Settlements
 
(1
)
 
(10
)
 
(4
)
 
(21
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
 
Transfers into level 3(4)
 

 

 

 

Transfers out of level 3(5)
 
8

 
3

 
8

 
(3
)
Balance, end of period
 
$
(63
)
 
$
243

 
$
(63
)
 
$
243

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
(9
)
 
$
45

 
$
(26
)
 
$
178

___________
(1)
For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(3)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and six months ended June 30, 2016 and 2015.
(4)
There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2016 and 2015.
(5)
We had $(8) million and $(3) million in losses transferred out of level 3 into level 2 for the three months ended June 30, 2016 and 2015, respectively, and $(8) million in losses and $3 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 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 each of the three and six months ended June 30, 2016 and 2015.
Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of June 30, 2016, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 7 years.
As of June 30, 2016 and December 31, 2015, the net forward notional buy (sell) position of our outstanding commodity and interest rate hedging instruments that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
June 30, 2016
 
December 31, 2015
Power (MWh)
 
(48
)
 
(41
)
Natural gas (MMBtu)
 
1,038

 
996

Environmental credits (Tonnes)
 
18

 
8

Interest rate hedging instruments
 
$
3,798

(1) 
$
1,320


___________
(1)
We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately $2.5 billion of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from 1.44% to 1.8125% for hedged interest payments. See Note 4 for a further discussion of our First Lien Term Loans.
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 June 30, 2016, was $129 million for which we have posted collateral of $14 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $8 million would be required and that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities 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 hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments 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 June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
  
Commodity
Instruments
 
Interest Rate
Hedging Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,231

 
$

 
$
1,231

Long-term derivative assets
360

 
9

 
369

Total derivative assets
$
1,591

 
$
9

 
$
1,600

 
 
 
 
 
 
Current derivative liabilities
$
1,323

 
$
37

 
$
1,360

Long-term derivative liabilities
453

 
59

 
512

Total derivative liabilities
$
1,776

 
$
96

 
$
1,872

Net derivative assets (liabilities)
$
(185
)
 
$
(87
)
 
$
(272
)

 
December 31, 2015
 
Commodity
Instruments
 
Interest Rate
Hedging Instruments
 
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
)


 
June 30, 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 hedging instruments
$
9

 
$
96

 
$
1

 
$
90

Total derivatives designated as cash flow hedging instruments
$
9

 
$
96

 
$
1

 
$
90

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
1,591

 
$
1,776

 
$
2,010

 
$
2,117

Total derivatives not designated as hedging instruments
$
1,591

 
$
1,776

 
$
2,010

 
$
2,117

Total derivatives
$
1,600

 
$
1,872

 
$
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 June 30, 2016 and December 31, 2015 (in millions):
 
 
June 30, 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
 
$
1,316

 
$
(1,237
)
 
$
(79
)
 
$

Commodity forward contracts
 
275

 
(232
)
 
(2
)
 
41

Interest rate hedging instruments
 
9

 

 

 
9

Total derivative assets
 
$
1,600

 
$
(1,469
)
 
$
(81
)
 
$
50

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,248
)
 
$
1,237

 
$
11

 
$

Commodity forward contracts
 
(528
)
 
232

 
12

 
(284
)
Interest rate hedging instruments
 
(96
)
 

 

 
(96
)
Total derivative (liabilities)
 
$
(1,872
)
 
$
1,469

 
$
23

 
$
(380
)
Net derivative assets (liabilities)
 
$
(272
)
 
$

 
$
(58
)
 
$
(330
)
 
 
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 hedging instruments
 
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 hedging instruments
 
(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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Realized gain (loss)(1)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
63

 
$
104

 
$
181

 
$
163

Total realized gain (loss)
$
63

 
$
104

 
$
181

 
$
163

 
 
 
 
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
 
 
 
 
Commodity derivative instruments
$
(36
)
 
$
(1
)
 
$
(131
)
 
$
69

Interest rate hedging instruments

 

 
1

 
1

Total mark-to-market gain (loss)
$
(36
)
 
$
(1
)
 
$
(130
)
 
$
70

Total activity, net
$
27

 
$
103

 
$
51

 
$
233

___________
(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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Realized and mark-to-market gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues(1)(2)
$
(272
)
 
$
115

 
$
(68
)
 
$
234

Derivatives contracts included in fuel and purchased energy expense(1)(2)
299

 
(12
)
 
118

 
(2
)
Interest rate hedging instruments included in interest expense(3)

 

 
1

 
1

Total activity, net
$
27

 
$
103

 
$
51

 
$
233


___________
(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.
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 June 30,
 
Three Months Ended June 30,
 
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 hedging instruments(1)(2)
$
(6
)
 
$
14

 
$
(11
)
 
$
(12
)
 
Interest expense
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
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 hedging instruments(1)(2)
$
(18
)
 
$
8

 
$
(22
)
 
$
(24
)
 
Interest expense
____________
(1)
We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and six months ended June 30, 2016 and 2015.
(2)
We recorded an income tax expense of nil for each of the three and six months ended June 30, 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 $143 million and $127 million at June 30, 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 June 30, 2016 and December 31, 2015, respectively.
We estimate that pre-tax net losses of $42 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 hedging instruments 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 June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
Margin deposits(1)
$
134

 
$
89

Natural gas and power prepayments
35

 
34

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
169

 
$
123

 
 
 
 
Letters of credit issued
$
622

 
$
600

First priority liens under power and natural gas agreements(3)
231

 
382

First priority liens under interest rate hedging instruments
97

 
92

Total letters of credit and first priority liens with our counterparties
$
950

 
$
1,074

 
 
 
 
Margin deposits posted with us by our counterparties(1)(4)
$
9

 
$
35

Letters of credit posted with us by our counterparties
23

 
24

Total margin deposits and letters of credit posted with us by our counterparties
$
32

 
$
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 June 30, 2016 and December 31, 2015, $159 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $10 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Includes $203 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at June 30, 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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Income tax expense (benefit)
$
(14
)
 
$
5

 
$
21

 
$
4

Effective tax rate
33
%
 
21
%
 
(10
)%
 
31
%

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 and six months ended June 30, 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 June 30, 2016, we had unrecognized tax benefits of $58 million. If recognized, $18 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 $13 million for income tax matters at June 30, 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.
Earnings (Loss) per Share
Earnings Per Share [Text Block]
Earnings (Loss) per Share
We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for each of the three and six months ended June 30, 2016, diluted loss per share for both periods is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the three and six months ended June 30, 2016 and 2015 are as follows (shares in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Diluted weighted average shares calculation:
 
 
 
 
 
 
 
Weighted average shares outstanding (basic)
354,066

 
366,975

 
353,784

 
369,938

Share-based awards

 
2,971

 

 
3,466

Weighted average shares outstanding (diluted)
354,066

 
369,946

 
353,784

 
373,404


We excluded the following items from diluted earnings (loss) per common share for the three and six months ended June 30, 2016 and 2015, because they were anti-dilutive (shares in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Share-based awards
3,335

 
5,042

 
3,294

 
5,042

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 $8 million and $7 million for the three months ended June 30, 2016 and 2015, respectively, and $15 million and $16 million for the six months ended June 30, 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 six months ended June 30, 2016 and 2015. At June 30, 2016, there was unrecognized compensation cost of $38 million related to restricted stock which is expected to be recognized over a weighted average period of 1.7 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 six months ended June 30, 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
2,941,831

 
$
12.40

Forfeited
166,018

 
$
16.32

Vested
1,275,797

 
$
19.01

Nonvested — June 30, 2016
5,028,286

 
$
15.86


The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2016 and 2015 was approximately $16 million and $33 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 nil and $(6) million for the three months ended June 30, 2016 and 2015, respectively, and $2 million and $(4) million for the six months ended June 30, 2016 and 2015, respectively.
A summary of our performance share unit activity for the six months ended June 30, 2016, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
517,906

 
$
23.36

Granted
657,807

 
$
14.81

Vested(1)
3,249

 
$
23.91

Nonvested — June 30, 2016
1,172,464

 
$
18.56


___________
(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. We have reached a resolution of this issue with the BAAQMD, which will not have a material impact on our financial condition, results of operations or cash flows.
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 June 30, 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 June 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
211

 
$
530

 
$
423

 
$

 
$
1,164

Intersegment revenues
1

 
4

 
4

 
(9
)
 

Total operating revenues
$
212

 
$
534

 
$
427

 
$
(9
)
 
$
1,164

Commodity Margin
$
254

 
$
160

 
$
243

 
$

 
$
657

Add: Mark-to-market commodity activity, net and other(1)
(62
)
 
7

 
28

 
(8
)
 
(35
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
98

 
85

 
96

 
(8
)
 
271

Depreciation and amortization expense
56

 
53

 
53

 

 
162

Sales, general and other administrative expense
8

 
14

 
12

 
1

 
35

Other operating expenses
7

 
2

 
10

 
(2
)
 
17

(Income) from unconsolidated investments in power plants

 

 
(3
)
 

 
(3
)
Income from operations
23

 
13

 
103

 
1

 
140

Interest expense, net of interest income
 
 
 
 
 
 
 
 
156

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
22

Loss before income taxes
 
 
 
 
 
 
 
 
$
(38
)

 
Three Months Ended June 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
421

 
$
570

 
$
451

 
$

 
$
1,442

Intersegment revenues

 
5

 
2

 
(7
)
 

Total operating revenues
$
421

 
$
575

 
$
453

 
$
(7
)
 
$
1,442

Commodity Margin
$
240

 
$
170

 
$
247

 
$

 
$
657

Add: Mark-to-market commodity activity, net and other(1)
(14
)
 
10

 
30

 
(7
)
 
19

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
120

 
82

 
77

 
(7
)
 
272

Depreciation and amortization expense
65

 
50

 
45

 

 
160

Sales, general and other administrative expense
6

 
15

 
9

 

 
30

Other operating expenses
10

 
2

 
8

 

 
20

(Income) from unconsolidated investments in power plants

 

 
(7
)
 

 
(7
)
Income from operations
25

 
31

 
145

 

 
201

Interest expense, net of interest income
 
 
 
 
 
 
 
 
157

Debt modification costs and other (income) expense, net
 
 
 
 
 
 
 
 
18

Income before income taxes
 
 
 
 
 
 
 
 
$
26


 
Six Months Ended June 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
635

 
$
1,062

 
$
1,082

 
$

 
$
2,779

Intersegment revenues
3

 
7

 
7

 
(17
)
 

Total operating revenues
$
638

 
$
1,069

 
$
1,089

 
$
(17
)
 
$
2,779

Commodity Margin
$
451

 
$
313

 
$
473

 
$

 
$
1,237

Add: Mark-to-market commodity activity, net and other(2)
(16
)
 
(103
)
 
7

 
(14
)
 
(126
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
189

 
171

 
180

 
(14
)
 
526

Depreciation and amortization expense
125

 
106

 
111

 

 
342

Sales, general and other administrative expense
18

 
30

 
24

 
1

 
73

Other operating expenses
15

 
4

 
20

 
(2
)
 
37

(Income) from unconsolidated investments in power plants

 

 
(10
)
 

 
(10
)
Income (loss) from operations
88

 
(101
)
 
155

 
1

 
143

Interest expense, net of interest income
 
 
 
 
 
 
 
 
312

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
28

Loss before income taxes
 
 
 
 
 
 
 
 
$
(197
)

 
Six Months Ended June 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
936

 
$
1,151

 
$
1,001

 
$

 
$
3,088

Intersegment revenues
2

 
8

 
4

 
(14
)
 

Total operating revenues
$
938

 
$
1,159

 
$
1,005

 
$
(14
)
 
$
3,088

Commodity Margin
$
458

 
$
319

 
$
415

 
$

 
$
1,192

Add: Mark-to-market commodity activity, net and other(2)
105

 
51

 
(22
)
 
(14
)
 
120

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
226

 
171

 
149

 
(14
)
 
532

Depreciation and amortization expense
132

 
99

 
87

 

 
318

Sales, general and other administrative expense
16

 
32

 
19

 

 
67

Other operating expenses
20

 
4

 
16

 

 
40

(Income) from unconsolidated investments in power plants

 

 
(12
)
 

 
(12
)
Income from operations
169


64


134



 
367

Interest expense, net of interest income
 
 
 
 
 
 
 
 
310

Debt modification and extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
39

Income before income taxes
 
 
 
 
 
 
 
 
$
18

_________
(1)
Includes $(20) million and $(18) million of lease levelization and $27 million and $3 million of amortization expense for the three months ended June 30, 2016 and 2015, respectively.
(2)
Includes $(42) million and $(42) million of lease levelization and $54 million and $7 million of amortization expense for the six months ended June 30, 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.
Business Interruption Proceeds — We record business interruption insurance proceeds when they are realizable and recorded approximately $8 million of business interruption proceeds in operating revenues during the three and six months ended June 30, 2016. We did not record any business interruption proceeds during the three and six months ended June 30, 2015.
At June 30, 2016 and December 31, 2015, the components of property, plant and equipment are stated at cost less accumulated depreciation
We consolidate all of our VIEs where we have determined that we are the primary beneficiary.
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.
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 hedging instruments. 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 hedging instruments 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 elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities 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 hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments 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.
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.
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
We did not record any material impairments during the three and six months ended June 30, 2016 and 2015.
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 March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We are currently assessing the potential 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 became effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period. 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 became effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period. 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 became effective for fiscal years beginning after December 15, 2015, including interim periods. 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 potential 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 standard, with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
Basis of Presentation and Summary of Significant Accounting Policies (Tables)
The table below represents the components of our restricted cash as of June 30, 2016 and December 31, 2015 (in millions):

 
June 30, 2016
 
December 31, 2015
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
34

 
$
8

 
$
42

 
$
28

 
$
8

 
$
36

Construction/major maintenance
36

 
9

 
45

 
50

 
2

 
52

Security/project/insurance
75

 
2

 
77

 
136

 

 
136

Other
3

 
1

 
4

 
2

 
2

 
4

Total
$
148

 
$
20

 
$
168

 
$
216

 
$
12

 
$
228

Property, Plant and Equipment, Net — At June 30, 2016 and December 31, 2015, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
June 30, 2016
 
December 31, 2015
 
Depreciable Lives
Buildings, machinery and equipment
$
16,712

 
$
16,294

 
3 – 46 Years
Geothermal properties
1,368

 
1,319

 
13 – 58 Years
Other
230

 
208

 
3 – 46 Years
 
18,310

 
17,821

 
 
Less: Accumulated depreciation
5,652

 
5,377

 
 
 
12,658

 
12,444

 
 
Land
121

 
120

 
 
Construction in progress
562

 
448

 
 
Property, plant and equipment, net
$
13,341

 
$
13,012

 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables)
At June 30, 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
June 30, 2016
 
June 30, 2016
 
December 31, 2015
Greenfield LP
50%
 
$
67

 
$
65

Whitby
50%
 
7

 
14

Total investments in power plants
 
 
$
74

 
$
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 June 30,
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
Greenfield LP
 
$
(1
)
 
$
(4
)
 
$
(5
)
 
$
(6
)
Whitby
 
(2
)
 
(3
)
 
(5
)
 
(6
)
Total
 
$
(3
)
 
$
(7
)
 
$
(10
)
 
$
(12
)

Aggregated summarized financial data for the six months ended June 30, 2016 and 2015 are set forth below (in millions):

Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
(Unaudited)

 
 
Six Months Ended June 30,
 
 
2016
 
2015
Revenues
 
$
75

 
$
98

Operating expenses
 
43

 
66

Income from operations
 
32

 
32

Interest expense, net of interest income
 
8

 
10

Other (income) expense, net
 
3

 
(1
)
Net income
 
$
21

 
$
23

Debt (Tables)
Our debt at June 30, 2016 and December 31, 2015, was as follows (in millions):
 
June 30, 2016

December 31, 2015
Senior Unsecured Notes
$
3,409

 
$
3,406

First Lien Term Loans
2,642

 
3,277

First Lien Notes
2,407

 
1,789

Project financing, notes payable and other
1,643

 
1,715

CCFC Term Loans
1,559

 
1,565

Capital lease obligations
181

 
185

Subtotal
11,841

 
11,937

Less: Current maturities
197

 
221

Total long-term debt
$
11,644

 
$
11,716

The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
June 30, 2016
 
December 31, 2015
2023 Senior Unsecured Notes
$
1,236

 
$
1,235

2024 Senior Unsecured Notes
642

 
641

2025 Senior Unsecured Notes
1,531

 
1,530

Total Senior Unsecured Notes
$
3,409

 
$
3,406

The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
 
June 30, 2016
 
December 31, 2015
2019 First Lien Term Loan
$

 
$
795

2020 First Lien Term Loan

 
378

2022 First Lien Term Loan
1,565

 
1,571

2023 First Lien Term Loan
531

 
533

New 2023 First Lien Term Loan
546

 

Total First Lien Term Loans
$
2,642

 
$
3,277

The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
 
June 30, 2016
 
December 31, 2015
2022 First Lien Notes
$
738

 
$
737

2023 First Lien Notes
569

 
568

2024 First Lien Notes
484

 
484

2026 First Lien Notes
616

 

Total First Lien Notes
$
2,407

 
$
1,789

The table below represents amounts issued under our letter of credit facilities at June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
Corporate Revolving Facility(1)
$
304

 
$
316

CDHI
261

 
241

Various project financing facilities
212

 
198

Total
$
777

 
$
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 June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
3,357

 
$
3,409

 
$
3,063

 
$
3,406

First Lien Term Loans
2,662

 
2,642

 
3,197

 
3,277

First Lien Notes
2,531

 
2,407

 
1,885

 
1,789

Project financing, notes payable and other(1)
1,595

 
1,551

 
1,653

 
1,608

CCFC Term Loans
1,537

 
1,559

 
1,494

 
1,565

Total
$
11,682

 
$
11,568

 
$
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 June 30, 2016 and December 31, 2015, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2016
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
383

 
$

 
$

 
$
383

Margin deposits
134

 

 

 
134

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,316

 

 

 
1,316

Commodity forward contracts(2)

 
232

 
43

 
275

Interest rate hedging instruments

 
9

 

 
9

Total assets
$
1,833

 
$
241

 
$
43

 
$
2,117

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
9

 
$

 
$

 
$
9

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,248

 

 

 
1,248

Commodity forward contracts(2)

 
422

 
106

 
528

Interest rate hedging instruments

 
96

 

 
96

Total liabilities
$
1,257

 
$
518

 
$
106

 
$
1,881

 
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)
$
1,134

 
$

 
$

 
$
1,134

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 hedging instruments

 
1

 

 
1

Total assets
$
2,959

 
$
221

 
$
54

 
$
3,234

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 hedging instruments

 
90

 

 
90

Total liabilities
$
1,639

 
$
503

 
$
100

 
$
2,242

___________
(1)
As of June 30, 2016 and December 31, 2015, we had cash equivalents of $215 million and $906 million included in cash and cash equivalents and $168 million and $228 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 June 30, 2016 and December 31, 2015:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
June 30, 2016
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(80
)
 
Discounted cash flow
 
Market price (per MWh)
 
$9.09 — $104.83/MWh
Power Congestion Products
 
$
17

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.47) — $11.76/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 June 30,
 
Six Months Ended June 30,
 
 
2016
 
2015
 
2016
 
2015
Balance, beginning of period
 
$
(65
)
 
$
203

 
$
(46
)
 
$
85

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
 
 
Included in net income (loss):
 
 
 
 
 
 
 
 
Included in operating revenues(1)
 
(174
)
 
45

 
(181
)
 
176

Included in fuel and purchased energy expense(2)
 
165

 

 
155

 
2

Purchases and settlements:
 
 
 
 
 
 
 
 
Purchases
 
4

 
2

 
5

 
4

Settlements
 
(1
)
 
(10
)
 
(4
)
 
(21
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
 
Transfers into level 3(4)
 

 

 

 

Transfers out of level 3(5)
 
8

 
3

 
8

 
(3
)
Balance, end of period
 
$
(63
)
 
$
243

 
$
(63
)
 
$
243

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
(9
)
 
$
45

 
$
(26
)
 
$
178

___________
(1)
For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(3)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and six months ended June 30, 2016 and 2015.
(4)
There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2016 and 2015.
(5)
We had $(8) million and $(3) million in losses transferred out of level 3 into level 2 for the three months ended June 30, 2016 and 2015, respectively, and $(8) million in losses and $3 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2016 and 2015, respectively, due to changes in market liquidity in various power markets.
Derivative Instruments (Tables)
As of June 30, 2016 and December 31, 2015, the net forward notional buy (sell) position of our outstanding commodity and interest rate hedging instruments that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
June 30, 2016
 
December 31, 2015
Power (MWh)
 
(48
)
 
(41
)
Natural gas (MMBtu)
 
1,038

 
996

Environmental credits (Tonnes)
 
18

 
8

Interest rate hedging instruments
 
$
3,798

(1) 
$
1,320


___________
(1)
We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately $2.5 billion of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from 1.44% to 1.8125% for hedged interest payments. See Note 4 for a further discussion of our First Lien Term Loans.
The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
  
Commodity
Instruments
 
Interest Rate
Hedging Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,231

 
$

 
$
1,231

Long-term derivative assets
360

 
9

 
369

Total derivative assets
$
1,591

 
$
9

 
$
1,600

 
 
 
 
 
 
Current derivative liabilities
$
1,323

 
$
37

 
$
1,360

Long-term derivative liabilities
453

 
59

 
512

Total derivative liabilities
$
1,776

 
$
96

 
$
1,872

Net derivative assets (liabilities)
$
(185
)
 
$
(87
)
 
$
(272
)

 
December 31, 2015
 
Commodity
Instruments
 
Interest Rate
Hedging Instruments
 
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
)
 
June 30, 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 hedging instruments
$
9

 
$
96

 
$
1

 
$
90

Total derivatives designated as cash flow hedging instruments
$
9

 
$
96

 
$
1

 
$
90

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
1,591

 
$
1,776

 
$
2,010

 
$
2,117

Total derivatives not designated as hedging instruments
$
1,591

 
$
1,776

 
$
2,010

 
$
2,117

Total derivatives
$
1,600

 
$
1,872

 
$
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 June 30, 2016 and December 31, 2015 (in millions):
 
 
June 30, 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
 
$
1,316

 
$
(1,237
)
 
$
(79
)
 
$

Commodity forward contracts
 
275

 
(232
)
 
(2
)
 
41

Interest rate hedging instruments
 
9

 

 

 
9

Total derivative assets
 
$
1,600

 
$
(1,469
)
 
$
(81
)
 
$
50

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,248
)
 
$
1,237

 
$
11

 
$

Commodity forward contracts
 
(528
)
 
232

 
12

 
(284
)
Interest rate hedging instruments
 
(96
)
 

 

 
(96
)
Total derivative (liabilities)
 
$
(1,872
)
 
$
1,469

 
$
23

 
$
(380
)
Net derivative assets (liabilities)
 
$
(272
)
 
$

 
$
(58
)
 
$
(330
)
 
 
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 hedging instruments
 
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 hedging instruments
 
(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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Realized gain (loss)(1)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
63

 
$
104

 
$
181

 
$
163

Total realized gain (loss)
$
63

 
$
104

 
$
181

 
$
163

 
 
 
 
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
 
 
 
 
Commodity derivative instruments
$
(36
)
 
$
(1
)
 
$
(131
)
 
$
69

Interest rate hedging instruments

 

 
1

 
1

Total mark-to-market gain (loss)
$
(36
)
 
$
(1
)
 
$
(130
)
 
$
70

Total activity, net
$
27

 
$
103

 
$
51

 
$
233

___________
(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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Realized and mark-to-market gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues(1)(2)
$
(272
)
 
$
115

 
$
(68
)
 
$
234

Derivatives contracts included in fuel and purchased energy expense(1)(2)
299

 
(12
)
 
118

 
(2
)
Interest rate hedging instruments included in interest expense(3)

 

 
1

 
1

Total activity, net
$
27

 
$
103

 
$
51

 
$
233


___________
(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.
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 June 30,
 
Three Months Ended June 30,
 
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 hedging instruments(1)(2)
$
(6
)
 
$
14

 
$
(11
)
 
$
(12
)
 
Interest expense
 
Six Months Ended June 30,
 
Six Months Ended June 30,
 
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 hedging instruments(1)(2)
$
(18
)
 
$
8

 
$
(22
)
 
$
(24
)
 
Interest expense
____________
(1)
We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and six months ended June 30, 2016 and 2015.
(2)
We recorded an income tax expense of nil for each of the three and six months ended June 30, 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 $143 million and $127 million at June 30, 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 June 30, 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 June 30, 2016 and December 31, 2015 (in millions):
 
June 30, 2016
 
December 31, 2015
Margin deposits(1)
$
134

 
$
89

Natural gas and power prepayments
35

 
34

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
169

 
$
123

 
 
 
 
Letters of credit issued
$
622

 
$
600

First priority liens under power and natural gas agreements(3)
231

 
382

First priority liens under interest rate hedging instruments
97

 
92

Total letters of credit and first priority liens with our counterparties
$
950

 
$
1,074

 
 
 
 
Margin deposits posted with us by our counterparties(1)(4)
$
9

 
$
35

Letters of credit posted with us by our counterparties
23

 
24

Total margin deposits and letters of credit posted with us by our counterparties
$
32

 
$
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 June 30, 2016 and December 31, 2015, $159 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $10 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Includes $203 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at June 30, 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 June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Income tax expense (benefit)
$
(14
)
 
$
5

 
$
21

 
$
4

Effective tax rate
33
%
 
21
%
 
(10
)%
 
31
%
Earnings (Loss) per Share (Tables)
Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the three and six months ended June 30, 2016 and 2015 are as follows (shares in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Diluted weighted average shares calculation:
 
 
 
 
 
 
 
Weighted average shares outstanding (basic)
354,066

 
366,975

 
353,784

 
369,938

Share-based awards

 
2,971

 

 
3,466

Weighted average shares outstanding (diluted)
354,066

 
369,946

 
353,784

 
373,404

We excluded the following items from diluted earnings (loss) per common share for the three and six months ended June 30, 2016 and 2015, because they were anti-dilutive (shares in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2016
 
2015
 
2016
 
2015
Share-based awards
3,335

 
5,042

 
3,294

 
5,042

Stock-Based Compensation (Tables)
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 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
2,941,831

 
$
12.40

Forfeited
166,018

 
$
16.32

Vested
1,275,797

 
$
19.01

Nonvested — June 30, 2016
5,028,286

 
$
15.86

A summary of our performance share unit activity for the six months ended June 30, 2016, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
517,906

 
$
23.36

Granted
657,807

 
$
14.81

Vested(1)
3,249

 
$
23.91

Nonvested — June 30, 2016
1,172,464

 
$
18.56


___________
(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 June 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
211

 
$
530

 
$
423

 
$

 
$
1,164

Intersegment revenues
1

 
4

 
4

 
(9
)
 

Total operating revenues
$
212

 
$
534

 
$
427

 
$
(9
)
 
$
1,164

Commodity Margin
$
254

 
$
160

 
$
243

 
$

 
$
657

Add: Mark-to-market commodity activity, net and other(1)
(62
)
 
7

 
28

 
(8
)
 
(35
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
98

 
85

 
96

 
(8
)
 
271

Depreciation and amortization expense
56

 
53

 
53

 

 
162

Sales, general and other administrative expense
8

 
14

 
12

 
1

 
35

Other operating expenses
7

 
2

 
10

 
(2
)
 
17

(Income) from unconsolidated investments in power plants

 

 
(3
)
 

 
(3
)
Income from operations
23

 
13

 
103

 
1

 
140

Interest expense, net of interest income
 
 
 
 
 
 
 
 
156

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
22

Loss before income taxes
 
 
 
 
 
 
 
 
$
(38
)

 
Three Months Ended June 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
421

 
$
570

 
$
451

 
$

 
$
1,442

Intersegment revenues

 
5

 
2

 
(7
)
 

Total operating revenues
$
421

 
$
575

 
$
453

 
$
(7
)
 
$
1,442

Commodity Margin
$
240

 
$
170

 
$
247

 
$

 
$
657

Add: Mark-to-market commodity activity, net and other(1)
(14
)
 
10

 
30

 
(7
)
 
19

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
120

 
82

 
77

 
(7
)
 
272

Depreciation and amortization expense
65

 
50

 
45

 

 
160

Sales, general and other administrative expense
6

 
15

 
9

 

 
30

Other operating expenses
10

 
2

 
8

 

 
20

(Income) from unconsolidated investments in power plants

 

 
(7
)
 

 
(7
)
Income from operations
25

 
31

 
145

 

 
201

Interest expense, net of interest income
 
 
 
 
 
 
 
 
157

Debt modification costs and other (income) expense, net
 
 
 
 
 
 
 
 
18

Income before income taxes
 
 
 
 
 
 
 
 
$
26


 
Six Months Ended June 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
635

 
$
1,062

 
$
1,082

 
$

 
$
2,779

Intersegment revenues
3

 
7

 
7

 
(17
)
 

Total operating revenues
$
638

 
$
1,069

 
$
1,089

 
$
(17
)
 
$
2,779

Commodity Margin
$
451

 
$
313

 
$
473

 
$

 
$
1,237

Add: Mark-to-market commodity activity, net and other(2)
(16
)
 
(103
)
 
7

 
(14
)
 
(126
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
189

 
171

 
180

 
(14
)
 
526

Depreciation and amortization expense
125

 
106

 
111

 

 
342

Sales, general and other administrative expense
18

 
30

 
24

 
1

 
73

Other operating expenses
15

 
4

 
20

 
(2
)
 
37

(Income) from unconsolidated investments in power plants

 

 
(10
)
 

 
(10
)
Income (loss) from operations
88

 
(101
)
 
155

 
1

 
143

Interest expense, net of interest income
 
 
 
 
 
 
 
 
312

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
28

Loss before income taxes
 
 
 
 
 
 
 
 
$
(197
)

 
Six Months Ended June 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
936

 
$
1,151

 
$
1,001

 
$

 
$
3,088

Intersegment revenues
2

 
8

 
4

 
(14
)
 

Total operating revenues
$
938

 
$
1,159

 
$
1,005

 
$
(14
)
 
$
3,088

Commodity Margin
$
458

 
$
319

 
$
415

 
$

 
$
1,192

Add: Mark-to-market commodity activity, net and other(2)
105

 
51

 
(22
)
 
(14
)
 
120

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
226

 
171

 
149

 
(14
)
 
532

Depreciation and amortization expense
132

 
99

 
87

 

 
318

Sales, general and other administrative expense
16

 
32

 
19

 

 
67

Other operating expenses
20

 
4

 
16

 

 
40

(Income) from unconsolidated investments in power plants

 

 
(12
)
 

 
(12
)
Income from operations
169


64


134



 
367

Interest expense, net of interest income
 
 
 
 
 
 
 
 
310

Debt modification and extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
39

Income before income taxes
 
 
 
 
 
 
 
 
$
18

_________
(1)
Includes $(20) million and $(18) million of lease levelization and $27 million and $3 million of amortization expense for the three months ended June 30, 2016 and 2015, respectively.
(2)
Includes $(42) million and $(42) million of lease levelization and $54 million and $7 million of amortization expense for the six months ended June 30, 2016 and 2015, respectively.
Basis of Presentation and Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Dec. 31, 2015
Accounting Policies [Line Items]
 
 
 
 
 
Asset Impairment Charges
$ 0 
$ 0 
$ 0 
$ 0 
 
Gain on Business Interruption Insurance Recovery
 
Prior Period Reclassification Adjustment
 
 
 
 
152 
Current
148 
 
148 
 
216 
Non-current
20 
 
20 
 
12 
Total
168 
 
168 
 
228 
Interest costs capitalized
 
Debt service
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
34 
 
34 
 
28 
Non-current
 
 
Total
42 
 
42 
 
36 
Construction major maintenance
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
36 
 
36 
 
50 
Non-current
 
 
Total
45 
 
45 
 
52 
Security project insurance
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
75 
 
75 
 
136 
Non-current
 
 
Total
77 
 
77 
 
136 
Other
 
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
 
Current
 
 
Non-current
 
 
Total
$ 4 
 
$ 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
Jun. 30, 2016
Dec. 31, 2015
Property, Plant and Equipment [Line Items]
 
 
Buildings, machinery and equipment
$ 16,712 
$ 16,294 
Geothermal properties
1,368 
1,319 
Other
230 
208 
Property, plant and equipment, gross
18,310 
17,821 
Less: Accumulated depreciation
5,652 
5,377 
Property, plant and equipment, gross, less accumulated depreciation, depletion and amortization
12,658 
12,444 
Land
121 
120 
Construction in progress
562 
448 
Property, plant and equipment, net
$ 13,341 
$ 13,012 
Acquisition (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended 3 Months Ended
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]
Jun. 30, 2016
South Point Energy Center [Member]
Apr. 1, 2016
South Point Energy Center [Member]
MW
Dec. 31, 2014
Osprey Energy Center [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
Ownership percentage of acquiree
 
75.00% 
25.00% 
 
 
 
 
Business combination, recognized identifiable assets acquired and liabilities assumed, net
$ 500 
 
 
$ 240 
 
 
 
Proceeds from Sale of Productive Assets
 
 
 
 
76 
 
166 
Net present value of transmission capacity payment obligations
 
 
 
 
 
112 
 
Remaining tribal lease costs
 
 
 
 
 
 
Near-term repairs, maintenance and capital improvements to restore the power plant to full capacity
 
 
 
 
 
$ 21 
 
Power generation capacity
745 
 
 
 
 
 
 
Summer Peaking Capacity
695 
 
 
 
 
504 
 
Osprey Energy Center Agreement Term
 
 
 
 
 
 
0 years 27 months 
Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
 
 
Equity method investments
$ 74 
$ 79 
Greenfield [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity method investments
67 
65 
Equity method investment, ownership percentage
50.00% 
 
Whitby [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity method investments
$ 7 
$ 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 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
(Income) from unconsolidated investments in power plants
$ (3)
$ (7)
$ (10)
$ (12)
Greenfield [Member]
 
 
 
 
(Income) from unconsolidated investments in power plants
(1)
(4)
(5)
(6)
Whitby [Member]
 
 
 
 
(Income) from unconsolidated investments in power plants
$ (2)
$ (3)
$ (5)
$ (6)
Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Dec. 31, 2015
Mar. 31, 2016
Greenfield [Member]
Jun. 30, 2016
Greenfield [Member]
MW
Jun. 30, 2015
Greenfield [Member]
Jun. 30, 2016
Whitby [Member]
MW
Jun. 30, 2016
Whitby [Member]
MW
Jun. 30, 2015
Whitby [Member]
Jun. 30, 2016
Variable Interest Entity, Primary Beneficiary [Member]
MW
Dec. 31, 2015
Variable Interest Entity, Primary Beneficiary [Member]
MW
Variable Interest Entity [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Power generation capacity
 
 
 
 
 
 
1,038 
 
50 
50 
 
10,266 
10,266 
Variable interest entity, financial or other support, amount
$ 0 
$ 0 
$ 0 
$ 0 
 
 
 
 
 
 
 
 
 
Equity method investment, ownership percentage
 
 
 
 
 
 
50.00% 
 
50.00% 
50.00% 
 
 
 
Equity method investment, summarized financial information, debt
279 
 
279 
 
269 
 
 
 
 
 
 
 
 
Prorata share of equity method investment, summarized financial information, debt
139 
 
139 
 
135 
 
 
 
 
 
 
 
 
Distribution from equity method investee
 
 
 
 
 
$ 5 
$ 0 
$ 0 
$ 13 
$ 13 
$ 13 
 
 
Variable Interest Entities and Unconsolidated Investments in Power Plants Variable Interest Entities and Unconsolidated Investments in Power Plants Condensed Financial Statements (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Condensed Financial Statements, Captions [Line Items]
 
 
 
 
Operating revenues
$ 1,164 
$ 1,442 
$ 2,779 
$ 3,088 
Operating expenses
1,027 
1,248 
2,646 
2,733 
Income from operations
140 
201 
143 
367 
Interest expense, net of interest income
(156)
(157)
(312)
(310)
Other (income) expense, net
(7)
(5)
(13)
(7)
Net income (loss)
(24)
21 
(218)
14 
Greenfield and Whitby [Member]
 
 
 
 
Condensed Financial Statements, Captions [Line Items]
 
 
 
 
Operating revenues
 
 
75 
98 
Operating expenses
 
 
43 
66 
Income from operations
 
 
32 
32 
Interest expense, net of interest income
 
 
10 
Other (income) expense, net
 
 
(1)
Net income (loss)
 
 
$ 21 
$ 23 
Debt (Debt) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
$ 11,841 
$ 11,937 
Debt, Current
197 
221 
Long-term Debt, Excluding Current Maturities
11,644 
11,716 
Unsecured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
3,409 
3,406 
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
2,642 
3,277 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
2,407 
1,789 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
1,643 
1,715 
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt and Capital Lease Obligations
1,559 
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
Jun. 30, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 11,682 
$ 11,292 
Senior Unsecured Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,236 
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
$ 3,409 
$ 3,406 
Debt (First Lien Term Loans) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 3 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Dec. 31, 2015
Jun. 30, 2016
First Lien Term Loan 2019 [Member]
Dec. 31, 2015
First Lien Term Loan 2019 [Member]
Jun. 30, 2016
2020 First Lien Term Loan [Member]
Dec. 31, 2015
2020 First Lien Term Loan [Member]
Jun. 30, 2016
2022 First Lien Term Loan [Member]
Dec. 31, 2015
2022 First Lien Term Loan [Member]
Jun. 30, 2016
2023 First Lien Term Loan [Member]
Dec. 31, 2015
2023 First Lien Term Loan [Member]
Jun. 30, 2016
New 2023 First Lien Term Loan [Member]
May 31, 2016
New 2023 First Lien Term Loan [Member]
Dec. 31, 2015
New 2023 First Lien Term Loan [Member]
Jun. 30, 2016
First Lien Term Loans [Member]
Dec. 31, 2015
First Lien Term Loans [Member]
Jun. 30, 2016
2019 and 2020 First Lien Term Loans [Member]
Jun. 30, 2016
Federal Funds Effective Rate [Member]
New 2023 First Lien Term Loan [Member]
Jun. 30, 2016
Eurodollar Rate For A One-Month Interest Period [Member]
New 2023 First Lien Term Loan [Member]
Jun. 30, 2016
Prime Rate or The Eurodollar Rate For A One-Month Interest Period [Member]
New 2023 First Lien Term Loan [Member]
Jun. 30, 2016
London Interbank Offered Rate (LIBOR) [Member]
New 2023 First Lien Term Loan [Member]
May 31, 2016
Minimum [Member]
London Interbank Offered Rate (LIBOR) [Member]
New 2023 First Lien Term Loan [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 562 
 
 
 
 
 
 
 
 
 
Long-term Debt
11,682 
 
11,682 
 
11,292 
795 
378 
1,565 
1,571 
531 
533 
546 
 
2,642 
3,277 
 
 
 
 
 
 
Debt Instrument, Basis Spread on Variable Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.50% 
1.00% 
2.00% 
3.00% 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.00% 
Debt Instrument Unamortized Discount Percent
 
 
 
 
 
 
 
 
 
 
 
 
 
1.00% 
 
 
 
 
 
 
 
 
 
 
Debt Issuance Costs, Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11 
 
 
 
 
 
 
 
 
 
Gain (Loss) on Extinguishment of Debt
$ (15)
$ (13)
$ (15)
$ (32)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 15 
 
 
 
 
 
Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
May 31, 2016
Dec. 31, 2015
Debt Instrument [Line Items]
 
 
 
Long-term Debt
$ 11,682 
 
$ 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
569 
 
568 
2024 First Lien Notes [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Long-term Debt
484 
 
484 
2026 First Lien Notes [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Debt Instrument, Face Amount
 
625 
 
Long-term Debt
616 
 
Debt Instrument, Interest Rate, Stated Percentage
 
5.25% 
 
Debt Issuance Costs, Net
 
 
Corporate Debt Securities [Member]
 
 
 
Debt Instrument [Line Items]
 
 
 
Long-term Debt
$ 2,407 
 
$ 1,789 
Debt (Letter of Credit) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 777 
$ 755 
Corporate Revolving Credit Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
304 1
316 1
CDH [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
261 
241 
Various Project Financing Facilities [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 212 
$ 198 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
$ 11,682 
$ 11,292 
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,409 
3,406 
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,642 
3,277 
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,407 
1,789 
Reported Value Measurement [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
11,568 
11,645 
Reported Value Measurement [Member] |
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,409 
3,406 
Reported Value Measurement [Member] |
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,642 
3,277 
Reported Value Measurement [Member] |
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,407 
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
1,551 1
1,608 1
Reported Value Measurement [Member] |
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,559 
1,565 
Fair Value, Inputs, Level 2 [Member] |
Unsecured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
3,357 
3,063 
Fair Value, Inputs, Level 2 [Member] |
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
2,662 
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
2,531 
1,885 
Fair Value, Inputs, Level 2 [Member] |
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
1,537 
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
$ 1,595 1
$ 1,653 1
Debt (Debt Textuals) (Details) (USD $)
12 Months Ended 3 Months Ended
Dec. 31, 2015
Jun. 30, 2016
Jun. 30, 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
Jun. 30, 2016
Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 383 1
$ 1,134 1
Margin deposits
134 2
89 2
Commodity futures contracts
1,316 
1,736 
Commodity forward contracts
275 3
274 3
Interest Rate Derivative Assets, Fair Value
Total assets
2,117 
3,234 
Margin deposits held by us posted by our counterparties
2 4
35 2 4
Commodity futures contracts
1,248 
1,604 
Commodity forward contracts
528 3
513 3
Interest Rate Derivative Liabilities At Fair Value
96 
90 
Liabilities, Fair Value Disclosure
1,881 
2,242 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
383 1
1,134 1
Margin deposits
134 
89 
Commodity futures contracts
1,316 
1,736 
Commodity forward contracts
3
3
Interest Rate Derivative Assets, Fair Value
Total assets
1,833 
2,959 
Margin deposits held by us posted by our counterparties
35 
Commodity futures contracts
1,248 
1,604 
Commodity forward contracts
3
3
Interest Rate Derivative Liabilities At Fair Value
Liabilities, Fair Value Disclosure
1,257 
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
232 3
220 3
Interest Rate Derivative Assets, Fair Value
Total assets
241 
221 
Margin deposits held by us posted by our counterparties
Commodity futures contracts
Commodity forward contracts
422 3
413 3
Interest Rate Derivative Liabilities At Fair Value
96 
90 
Liabilities, Fair Value Disclosure
518 
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
43 3
54 3
Interest Rate Derivative Assets, Fair Value
Total assets
43 
54 
Margin deposits held by us posted by our counterparties
Commodity futures contracts
Commodity forward contracts
106 3
100 3
Interest Rate Derivative Liabilities At Fair Value
Liabilities, Fair Value Disclosure
$ 106 
$ 100 
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) (USD $)
Jun. 30, 2016
Dec. 31, 2015
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
$ (272,000,000)
$ (196,000,000)
Power Contracts [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Derivative, Fair Value, Net
(80,000,000)
(54,000,000)
Power Contracts [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
9.09 
6.72 
Power Contracts [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
104.83 
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
17,000,000 
8,000,000 
Power Congestion Products [Member] |
Minimum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
(11.47)
(11.47)
Power Congestion Products [Member] |
Maximum [Member]
 
 
Fair Value Inputs, Assets, Quantitative Information [Line Items]
 
 
Fair Value Inputs Quantitative Information
$ 11.76 
$ 12.19 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Dec. 31, 2015
Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
 
Balance, beginning of period
$ (65)
$ 203 
$ (46)
$ 85 
 
 
Included in net income:
 
 
 
 
 
 
Included in operating revenues
(174)1
45 1
(181)1
176 1
 
 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense
165 2
2
155 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
(1)
(10)
(4)
(21)
 
 
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
3 4
3 4
 
 
Transfers out of Level 3
4 5
4 5
4 5
(3)4 5
 
 
Balance, end of period
(63)
243 
(63)
243 
 
 
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)
(9)
45 
(26)
178 
 
 
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
 
 
 
 
 
 
Cash and Cash Equivalents, at Carrying Value
215 
422 
215 
422 
906 
717 
Restricted Cash and Cash Equivalents
168 
 
168 
 
228 
 
Fair Value Measurement [Domain]
 
 
 
 
 
 
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
 
 
 
 
 
 
Cash and Cash Equivalents, at Carrying Value
215 
 
215 
 
906 
 
Restricted Cash and Cash Equivalents
$ 168 
 
$ 168 
 
$ 228 
 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended 12 Months Ended 6 Months Ended 12 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2016
Power [Member]
MWh
Dec. 31, 2014
Power [Member]
MWh
Jun. 30, 2016
Natural Gas [Member]
MMBTU
Dec. 31, 2014
Natural Gas [Member]
MMBTU
Jun. 30, 2016
Environmental Credits [Member]
t
Dec. 31, 2014
Environmental Credits [Member]
t
Jun. 30, 2016
Interest Rate Hedging Instruments
Dec. 31, 2015
Interest Rate Hedging Instruments
Derivative [Line Items]
 
 
 
 
 
 
 
 
Derivative, Nonmonetary Notional Amount, Energy Measure
(48)
(41)
1,038 
996 
 
 
 
 
Derivative, Nonmonetary Notional Amount, Mass
 
 
 
 
18 
 
 
Derivative, Notional Amount
 
 
 
 
 
 
$ 3,798 1
$ 1,320 
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
$ 1,231 
$ 1,698 
Long-term derivative assets
369 
313 
Total derivative assets
1,600 
2,011 
Derivative liabilities, current
1,360 
1,734 
Long-term derivative liabilities
512 
473 
Total derivative liabilities
1,872 
2,207 
Derivative, Fair Value, Net
(272)
(196)
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
Total derivative liabilities
96 
90 
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
1,591 
2,010 
Total derivative liabilities
1,776 
2,117 
Interest Rate Hedging Instruments
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
Derivative Assets, Noncurrent
Total derivative assets
Current derivative liabilities
37 
37 
Derivative Liabilities, Noncurrent
59 
53 
Total derivative liabilities
96 
90 
Derivative, Fair Value, Net
(87)
(89)
Interest Rate Hedging Instruments |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
Total derivative liabilities
96 
90 
Energy Related Derivative [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Derivative assets, current
1,231 
1,698 
Derivative Assets, Noncurrent
360 
312 
Total derivative assets
1,591 
2,010 
Current derivative liabilities
1,323 
1,697 
Derivative Liabilities, Noncurrent
453 
420 
Total derivative liabilities
1,776 
2,117 
Derivative, Fair Value, Net
(185)
(107)
Energy Related Derivative [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Total derivative assets
1,591 
2,010 
Total derivative liabilities
$ 1,776 
$ 2,117 
Derivative Instruments (Detail 3) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
$ 1,600 
$ 2,011 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(1,469)
(1,804)
Derivative, Collateral, Obligation to Return Cash
(81)1
(137)1
Derivative Liability, Fair Value, Gross Liability
(1,872)
(2,207)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
1,469 
1,804 
Derivative, Collateral, Right to Reclaim Cash
23 1
1
Derivative, Fair Value, Net
(272)
(196)
Derivative Fair Value, Amount Not Offset Against Collateral, Net
Margin/Cash (Received) Posted Subject to Master Netting Arrangement
(58)1
(132)1
Derivative Asset, Fair Value, Amount Offset Against Collateral
50 
70 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(380)
(398)
Derivative, Fair Value, Amount Offset Against Collateral, Net
(330)
(328)
Commodity Exchange Traded Futures and Swaps Contracts [Member]
 
 
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
 
 
Derivative Asset, Fair Value, Gross Asset
1,316 
1,736 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(1,237)
(1,602)
Derivative, Collateral, Obligation to Return Cash
(79)1
(134)1
Derivative Liability, Fair Value, Gross Liability
(1,248)
(1,604)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
1,237 
1,602 
Derivative, Collateral, Right to Reclaim Cash
11 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
275 
274 
Derivative Asset, Fair Value, Amount Not Offset Against Collateral
(232)
(202)
Derivative, Collateral, Obligation to Return Cash
(2)1
(3)1
Derivative Liability, Fair Value, Gross Liability
(528)
(513)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
232 
202 
Derivative, Collateral, Right to Reclaim Cash
12 1
1
Derivative Asset, Fair Value, Amount Offset Against Collateral
41 
69 
Derivative Liability, Fair Value, Amount Offset Against Collateral
(284)
(308)
Interest Rate Hedging Instruments
 
 
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
(96)
(90)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral
Derivative, Collateral, Right to Reclaim Cash
1
1
Derivative, Fair Value, Net
(87)
(89)
Derivative Asset, Fair Value, Amount Offset Against Collateral
Derivative Liability, Fair Value, Amount Offset Against Collateral
$ (96)
$ (90)
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Power contracts included in operating revenues
$ 1,164 
$ 1,442 
$ 2,779 
$ 3,088 
Natural gas contracts included in fuel and purchased energy expense
542 
766 
1,668 
1,776 
Interest expense
157 
158 
314 
312 
Gain (Loss) on Derivative Instruments, Net, Pretax
27 
103 
51 
233 
Gain (Loss) on Sale of Derivatives
63 1 2
104 1 2
181 1 2
163 1 2
Mark-to-market gain (loss)
(36)3
(1)3
(130)3
70 3
Power [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Power contracts included in operating revenues
(272)1 2
115 1 2
(68)1 2
234 1 2
Interest Rate Contract [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Interest expense
3
3
3
3
Mark-to-market gain (loss)
3
3
3
3
Energy Related Derivative [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Gain (Loss) on Sale of Derivatives
63 1 2
104 1 2
181 1 2
163 1 2
Mark-to-market gain (loss)
(36)3
(1)3
(131)3
69 3
Natural Gas [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Natural gas contracts included in fuel and purchased energy expense
$ 299 1 2
$ (12)1 2
$ 118 1 2
$ (2)1 2
Derivative Instruments (Details 5) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Interest expense
$ 157 
$ 158 
$ 314 
$ 312 
Interest Rate Hedging Instruments
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net
(6)1 2
14 1 2
(18)1 2
1 2
Interest expense
3
3
3
3
Reclassification out of Accumulated Other Comprehensive Income [Member] |
Interest Rate Hedging Instruments
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Interest expense
$ (11)1 2 4
$ (12)1 2 4
$ (22)1 2 4
$ (24)1 2 4
Derivative Instruments (Textuals) (Details) (USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Parent [Member]
Dec. 31, 2015
Parent [Member]
Jun. 30, 2016
Noncontrolling Interest [Member]
Dec. 31, 2015
Noncontrolling Interest [Member]
Jun. 30, 2016
Interest Rate Hedging Instruments
Jun. 30, 2016
Interest Rate Cap Redemption Period 1
Jun. 30, 2016
Interest Rate Cap Redemption Period 2
Derivatives, Fair Value [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Derivative, Amount of Hedged Item
 
 
 
 
 
 
 
 
$ 2,500,000,000 
 
 
Derivative, Cap Interest Rate
 
 
 
 
 
 
 
 
 
1.44% 
1.8125% 
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax
 
 
 
 
 
 
 
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax
 
 
 
 
143,000,000 
127,000,000 
13,000,000 
11,000,000 
 
 
 
Summary of Derivative Instruments [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Maximum length of time hedging using interest rate derivative instruments
 
 
7 years 
 
 
 
 
 
 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
129,000,000 
 
129,000,000 
 
 
 
 
 
 
 
 
Collateral Already Posted, Aggregate Fair Value
14,000,000 
 
14,000,000 
 
 
 
 
 
 
 
 
Additional Collateral, Aggregate Fair Value
8,000,000 
 
8,000,000 
 
 
 
 
 
 
 
 
Cash Flow Hedge (Gain) Loss to be Reclassified within Twelve Months
 
 
$ 42,000,000 
 
 
 
 
 
 
 
 
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2016
Dec. 31, 2015
Financial Instruments Owned and Pledged as Collateral [Line Items]
 
 
Margin deposits
$ 134 1
$ 89 1
Natural gas and power prepayments
35 
34 
Total margin deposits and natural gas and power prepayments with our counterparties
169 2
123 2
Letters of credit issued
622 
600 
First priority liens under power and natural gas agreements
231 3
382 3
First priority liens under interest rate hedging instruments
97 
92 
Total letters of credit and first priority liens with our counterparties
950 
1,074 
Margin deposits held by us posted by our counterparties
1 4
35 1 4
Letters of credit posted with us by our counterparties
23 
24 
Total margin deposits and letters of credit posted with us by our counterparties
32 
59 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
10 
22 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
159 
101 
Champion Energy [Member]
 
 
Financial Instruments Owned and Pledged as Collateral [Line Items]
 
 
First priority liens under power and natural gas agreements
$ 203 
$ 345 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Income Tax Contingency [Line Items]
 
 
 
 
Income tax (expense) benefit
$ 14 
$ (5)
$ (21)
$ (4)
Effective Income Tax Rate, Continuing Operations
33.00% 
21.00% 
(10.00%)
31.00% 
Income Tax Uncertainties [Abstract]
 
 
 
 
Unrecognized Tax Benefits
58 
 
58 
 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
18 
 
18 
 
Unrecognized Tax Benefit Related to Deferred Tax Asset
40 
 
40 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
13 
 
13 
 
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 
 
$ 18 
 
Earnings (Loss) per Share Reconciliation of Basic to Diluted Weighted Average Shares Outstanding (Details)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Earnings (Loss) per Share [Abstract]
 
 
 
 
Weighted Average Number of Shares Outstanding, Basic
354,066 
366,975 
353,784 
369,938 
Weighted Average Number Diluted Shares Outstanding Adjustment
2,971 
3,466 
Weighted Average Number of Shares Outstanding, Diluted
354,066 
369,946 
353,784 
373,404 
Earnings (Loss) per Share (Details)
In Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Earnings Per Share [Abstract]
 
 
 
 
Share-based awards
3,335 
5,042 
3,294 
5,042 
Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) (Restricted Stock [Member], USD $)
6 Months Ended
Jun. 30, 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
5,028,286 
3,528,270 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 15.86 
$ 19.91 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
2,941,831 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value
$ 12.40 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period
166,018 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value
$ 16.32 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period
1,275,797 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value
$ 19.01 
 
Stock-Based Compensation (Stock Based Compensation Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Allocated Share-based Compensation Expense
$ 8 
$ 7 
$ 15 
$ 16 
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards
(6)
(4)
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
38 
 
38 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
1 year 8 months 12 days 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value
 
 
$ 16 
$ 33 
Stock-Based Compensation Liability Based Stock Compensation (Details) (Performance Shares [Member], USD $)
6 Months Ended
Jun. 30, 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
1,172,464 
517,906 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value
$ 18.56 
$ 23.36 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period
657,807 
 
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 6 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
$ 1,164 
$ 1,442 
$ 2,779 
$ 3,088 
Commodity Margin
657 
657 
1,237 
1,192 
Add: Mark-to-market commodity activity, net and other
(35)1
19 1
(126)2
120 2
Plant operating expense
271 
272 
526 
532 
Depreciation and amortization expense
162 
160 
342 
318 
Sales, general and other administrative expense
35 
30 
73 
67 
Other operating expenses
17 
20 
37 
40 
(Income) loss from unconsolidated investments in power plants
(3)
(7)
(10)
(12)
Income from operations
140 
201 
143 
367 
Interest expense, net of interest income
156 
157 
312 
310 
Debt Extinguishment Costs and Other (Income) Expense, Net
22 
18 
28 
39 
Income (loss) before income taxes
(38)
26 
(197)
18 
Lease levelization
(20)
(18)
(42)
(42)
Amortization of Intangible Assets
27 
54 
West [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
212 
421 
638 
938 
Commodity Margin
254 
240 
451 
458 
Add: Mark-to-market commodity activity, net and other
(62)1
(14)1
(16)2
105 2
Plant operating expense
98 
120 
189 
226 
Depreciation and amortization expense
56 
65 
125 
132 
Sales, general and other administrative expense
18 
16 
Other operating expenses
10 
15 
20 
(Income) loss from unconsolidated investments in power plants
Income from operations
23 
25 
88 
169 
Texas [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
534 
575 
1,069 
1,159 
Commodity Margin
160 
170 
313 
319 
Add: Mark-to-market commodity activity, net and other
1
10 1
(103)2
51 2
Plant operating expense
85 
82 
171 
171 
Depreciation and amortization expense
53 
50 
106 
99 
Sales, general and other administrative expense
14 
15 
30 
32 
Other operating expenses
(Income) loss from unconsolidated investments in power plants
Income from operations
13 
31 
(101)
64 
East [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
427 
453 
1,089 
1,005 
Commodity Margin
243 
247 
473 
415 
Add: Mark-to-market commodity activity, net and other
28 1
30 1
2
(22)2
Plant operating expense
96 
77 
180 
149 
Depreciation and amortization expense
53 
45 
111 
87 
Sales, general and other administrative expense
12 
24 
19 
Other operating expenses
10 
20 
16 
(Income) loss from unconsolidated investments in power plants
(3)
(7)
(10)
(12)
Income from operations
103 
145 
155 
134 
Consolidation, Eliminations [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
(9)
(7)
(17)
(14)
Commodity Margin
Add: Mark-to-market commodity activity, net and other
(8)1
(7)1
(14)2
(14)2
Plant operating expense
(8)
(7)
(14)
(14)
Depreciation and amortization expense
Sales, general and other administrative expense
Other operating expenses
(2)
(2)
(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
1,164 
1,442 
2,779 
3,088 
Operating Segments [Member] |
West [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
211 
421 
635 
936 
Operating Segments [Member] |
Texas [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
530 
570 
1,062 
1,151 
Operating Segments [Member] |
East [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Operating revenues
423 
451 
1,082 
1,001 
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
$ (9)
$ (7)
$ (17)
$ (14)