CALPINE CORP, 10-Q filed on 7/27/2012
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2012
Jul. 24, 2012
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, 2012 
 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q2 
 
Amendment Flag
false 
 
Entity Common Stock, Shares Outstanding
 
466,616,007 
Consolidated Statements of Operations (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Operating revenues
$ 879 
$ 1,633 
$ 2,115 
$ 3,132 
Operating expenses:
 
 
 
 
Fuel and purchased energy expense
612 
1,000 
1,244 
2,069 
Plant operating expense
271 
261 
492 
499 
Depreciation and amortization expense
138 
131 
278 
262 
Sales, general and other administrative expense
35 
34 
68 
66 
Other operating expense
21 
22 
45 
42 
Total operating expenses
1,077 
1,448 
2,127 
2,938 
(Income) loss from unconsolidated investments in power plants
(5)
2 
(14)
(7)
Income from operations
(193)
183 
2 
201 
Interest expense
184 
192 
369 
383 
Loss on interest rate derivatives
0 
37 
14 
146 
Interest (income)
(2)
(2)
(5)
(5)
Debt extinguishment costs
0 
5 
12 
98 
Other (income) expense, net
6 
3 
8 
10 
Income (loss) before income taxes and discontinued operations
(381)
(52)
(396)
(431)
Income tax expense (benefit)
(52)
18 
(58)
(65)1
Net income (loss)
(329)
(70)
(338)
(366)
Net (income) loss attributable to the noncontrolling interest
0 
0 
0 
(1)
Net income (loss) attributable to Calpine
$ (329)
$ (70)
$ (338)
$ (367)
Basic and diluted earnings (loss) per common share attributable to Calpine:
 
 
 
 
Weighted Average Number of Shares Outstanding, Basic and Diluted
471,444 
486,411 
474,775 
486,334 
Earnings Per Share, Basic and Diluted
$ (0.69)
$ (0.14)
$ (0.71)
$ (0.75)
Consolidated Statements of Comprehensive Income (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Net income (loss)
$ (329)
$ (70)
$ (338)
$ (366)
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
(44)
(17)
(34)
14 
Reclassification adjustment for (gain) loss on cash flow hedges realized in net (income) loss
(4)
(31)
(14)
44 
Foreign currency translation gain (loss)
(4)
(1)
(1)
0 
Income tax (expense) benefit
2 
18 
4 
(16)
Other comprehensive income (loss)
(50)
(31)
(45)
42 
Comprehensive income (loss)
(379)
(101)
(383)
(324)
Comprehensive (income) loss attributable to the noncontrolling interest
0 
0 
0 
(1)
Comprehensive income (loss) attributable to Calpine
$ (379)
$ (101)
$ (383)
$ (325)
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Current assets:
 
 
Cash and cash equivalents ($169 and $285 attributable to VIEs)
$ 587 
$ 1,252 
Accounts receivable, net of allowance of $14 and $13
532 
598 
Margin deposits and other prepaid expense
305 
193 
Restricted cash, current ($85 and $57 attributable to VIEs)
124 
139 
Derivative Assets, Current
1,049 
1,051 
Inventory and other current assets
337 
329 
Total current assets
2,934 
3,562 
Property, plant and equipment, net ($4,473 and $4,313 attributable to VIEs)
13,109 
13,019 
Restricted cash, net of current portion ($50 and $53 attributable to VIEs)
51 
55 
Investments
76 
80 
Derivative Assets, Noncurrent
158 
113 
Other assets
559 
542 
Total assets
16,887 
17,371 
Current liabilities:
 
 
Accounts payable
353 
435 
Accrued interest payable ($25 and $19 attributable to VIEs)
200 
200 
Debt, current portion ($39 and $41 attributable to VIEs)
103 
104 
Derivative liabilities, current
1,243 
1,144 
Other current liabilities
274 
279 
Total current liabilities
2,173 
2,162 
Debt, net of current portion ($2,731 and $2,522 attributable to VIEs)
10,488 
10,321 
Derivative Liabilities, Noncurrent
276 
279 
Other long-term liabilities
247 
245 
Total liabilities
13,184 
13,007 
Commitments and contingencies (see Note 10)
   
   
Stockholders’ equity:
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding
0 
0 
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 492,024,794 and 490,468,815 shares issued, respectively, and 466,615,007 and 481,743,738 shares outstanding, respectively
1 
1 
Treasury stock, at cost, 25,409,787 and 8,725,077 shares, respectively
(420)
(125)
Additional paid-in capital
12,320 
12,305 
Accumulated deficit
(8,037)
(7,699)
Accumulated other comprehensive loss
(223)
(178)
Total Calpine stockholders’ equity
3,641 
4,304 
Noncontrolling interest
62 
60 
Total stockholders’ equity
3,703 
4,364 
Total liabilities and stockholders’ equity
16,887 
17,371 
Cash and Cash Equivalents At Carrying Value Attributable to VIE
169 
285 
Allowance for Doubtful Accounts Receivable, Current
14 
13 
Restricted Cash And Cash Equivalents At Carrying Value Attributable To VIE
85 
57 
Property Plant And Equipment Net Attributable To VIE
4,473 
4,313 
Restricted Cash And Cash Equivalents Noncurrent Attributable To VIE
50 
53 
Accrued Interest Attributable To VIE
25 
19 
Debt Current Attributable To VIE
39 
41 
Long Term Debt Noncurrent Attributable To VIE
$ 2,731 
$ 2,522 
Preferred Stock, Par or Stated Value Per Share
$ 0 
$ 0 
Preferred Stock, Shares Authorized
100 
100 
Preferred Stock, Shares Issued
0 
0 
Preferred Stock, Shares Outstanding
0 
0 
Common Stock, Par or Stated Value Per Share
$ 0 
$ 0 
Common Stock, Shares Authorized
1,400 
1,400 
Common Stock, Shares, Issued
492 
490 
Common Stock, Shares, Outstanding
467 
482 
Treasury Stock, Shares
25 
9 
Consolidated Statements of Cash Flows (USD $)
In Millions, unless otherwise specified
6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Cash flows from operating activities:
 
 
Net income (loss)
$ (338)
$ (366)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization expense
299 1
279 1
Debt extinguishment costs
0 
85 
Deferred income taxes
(31)
(90)
(Gain) loss on sale of power plants and other, net
4 
9 
Unrealized mark-to-market activities, net
119 2
77 2
(Income) loss from unconsolidated investments in power projects
(14)
(7)
Return on unconsolidated investments in power plants
16 
6 
Stock-based compensation expense
13 
12 
Other
1 
5 
Change in operating assets and liabilities, net of effects of acquisitions:
 
 
Accounts receivable
63 
(68)
Derivative instruments, net
(111)
(29)
Other assets
(122)
58 
Accounts payable and accrued expenses
(86)
166 
Settlement of non-hedging interest rate swaps
156 
103 
Other liabilities
(1)
(1)
Net cash provided by (used in) operating activities
(32)
239 
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(369)
(341)
Settlement of non-hedging interest rate swaps
(156)
(103)
(Increase) decrease in restricted cash
19 
30 
Purchases of deferred transmission credits
(12)
(8)
Other
5 
1 
Net cash used in investing activities
(513)
(421)
Cash flows from financing activities:
 
 
Repayment of Term Loans
(8)
0 
Borrowings under Term Loan and New Term Loan
0 
1,657 
Repayments on NDH Project Debt
0 
(1,283)
Issuance of First Lien Notes
0 
1,200 
Repayments on First Lien Credit Facility
0 
(1,187)
Borrowings from project financing, notes payable and other
226 
69 
Repayments of project financing, notes payable and other
(46)
(419)
Capital contributions from noncontrolling interest holder
0 
34 
Financing costs
(5)
(67)
Stock repurchases
(290)
0 
Other
3 
(2)
Net cash provided by (used in) financing activities
(120)
2 
Net increase (decrease) in cash and cash equivalents
(665)
(180)
Cash and cash equivalents, beginning of period
1,252 
1,327 
Cash and cash equivalents, end of period
587 
1,147 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
352 
292 
Income taxes
13 
12 
Supplemental disclosure of non-cash investing and financing activities:
 
 
Change in capital expenditures included in accounts payable
$ 3 
$ 21 
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies
Basis of Presentation and Summary of Significant Accounting Policies
We are an independent wholesale power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We engage in the purchase of natural gas and fuel oil as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to economically hedge our 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, 2011, included in our 2011 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, intraperiod provisions for income taxes computed in accordance with U.S. GAAP, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At June 30, 2012 and December 31, 2011, we had cash and cash equivalents of $178 million and $306 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.
The table below represents the components of our restricted cash as of June 30, 2012 and December 31, 2011 (in millions):

 
June 30, 2012
 
December 31, 2011
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
16

 
$
42

 
$
58

 
$
11

 
$
42

 
$
53

Rent reserve
7

 
—

 
7

 
—

 
—

 
—

Construction/major maintenance
47

 
2

 
49

 
33

 
10

 
43

Security/project/insurance
54

 
5

 
59

 
79

 
—

 
79

Other
—

 
2

 
2

 
16

 
3

 
19

Total
$
124

 
$
51

 
$
175

 
$
139

 
$
55

 
$
194

___________
(1)
At both June 30, 2012 and December 31, 2011, amounts restricted for debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.
Inventory — At June 30, 2012 and December 31, 2011, we had inventory of $262 million and $294 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Property, Plant and Equipment, Net — At June 30, 2012 and December 31, 2011, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
June 30, 2012
 
December 31, 2011
Buildings, machinery and equipment
$
15,154

 
$
15,074

Geothermal properties
1,199

 
1,163

Other
157

 
156

 
16,510

 
16,393

Less: Accumulated depreciation
4,405

 
4,158

 
12,105

 
12,235

Land
90

 
91

Construction in progress
914

 
693

Property, plant and equipment, net
$
13,109

 
$
13,019


Capitalized Interest — The total amount of interest capitalized was $9 million and $4 million for the three months ended June 30, 2012 and 2011, respectively, and $17 million and $11 million for the six months ended June 30, 2012 and 2011, respectively.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements related to power plants under construction, at June 30, 2012, are as follows (in millions):
2012
$
285

2013
527

2014
465

2015
481

2016
396

Thereafter
2,312

Total
$
4,466

 
 

Treasury Stock — During the six months ended June 30, 2012, we repurchased common stock with a value of $290 million under our share repurchase program and withheld shares with a value of $5 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees under the Equity Plan.
New Accounting Standards and Disclosure Requirements
Fair Value Measurement — In May 2011, the FASB issued Accounting Standards Update 2011-04, “Fair Value Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating to fair value measurements. The update stems from the FASB and the International Accounting Standards Board project to develop common requirements for measuring fair value and for disclosing information about fair value measurements. The update did not impact any of our fair value measurements but did require disclosure of the following:
•
quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy;
•
for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and
•
the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.
The new requirements relating to fair value measurements are prospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption prohibited. We adopted all of the requirements related to this update at January 1, 2012. Since this update did not impact any of our fair value measurements and only required additional disclosures, adoption of this standard did not have a material impact on our results of operations, cash flows or financial condition.
Disclosures about Offsetting Assets and Liabilities — In December 2011, the FASB issued Accounting Standards Update 2011-11, “Balance Sheet - Disclosures about Offsetting Assets and Liabilities” to enhance disclosure requirements relating to the offsetting of assets and liabilities on an entity's balance sheet. The update requires enhanced disclosures regarding assets and liabilities that are presented net or gross in the statement of financial position when the right of offset exists, or that are subject to an enforceable master netting arrangement. The new disclosure requirements relating to this update are retrospective and effective for annual and interim periods beginning on or after January 1, 2013. The update only requires additional disclosures, as such, we do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.
Variable Interest Entities and Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
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, 2012. See Note 5 in our 2011 Form 10-K for further information regarding our VIEs.
Riverside Energy Center
Our 603 MW Riverside Energy Center has a PPA that provides WP&L an option to purchase the power plant and plant-related assets for approximately $392 million upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase Riverside Energy Center, LLC, one of our VIEs which owns Riverside Energy Center. The sale is expected to close in December 2012 and is subject to federal regulatory approval. The assets being disposed of did not meet the criteria for classification as held for sale under U.S. GAAP, and we do not expect any gain (loss) on sale. At June 30, 2012, Riverside Energy Center, LLC had total assets of $422 million and total liabilities of $5 million.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 10,500 MW and 11,391 MW, at June 30, 2012 and December 31, 2011, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Calpine Corporation provided support to these VIEs in the form of cash and other contributions other than amounts contractually required of nil during both the three months ended June 30, 2012 and 2011, and nil and $72 million during the six months ended June 30, 2012 and 2011, respectively.
U.S. GAAP requires separate disclosure on the face of our Consolidated Condensed Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider whether this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
Unconsolidated VIEs and Investments
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Condensed Balance Sheets. At June 30, 2012 and December 31, 2011, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of June 30, 2012
 
June 30, 2012
 
December 31, 2011
Greenfield LP
50%
 
$
69

 
$
72

Whitby
50%
 
7

 
8

Total investments
 
 
$
76

 
$
80


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, 2012 and December 31, 2011, equity method investee debt was approximately $448 million and $462 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $224 million and $231 million at June 30, 2012 and December 31, 2011, respectively.
Our equity interest in the net income (loss) from Greenfield LP and Whitby for the three and six months ended June 30, 2012 and 2011 is recorded in (income) loss from unconsolidated investments in power plants. The following table sets forth details of our (income) loss from unconsolidated investments in power plants for the periods indicated (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Greenfield LP
$
(2
)
 
$
4

 
$
(8
)
 
$
(1
)
Whitby
(3
)
 
(2
)
 
(6
)
 
(6
)
Total
$
(5
)
 
$
2

 
$
(14
)
 
$
(7
)

Greenfield LP — 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. Greenfield LP holds an 18-year term loan in the amount of CAD $648 million. Borrowings under the project finance facility bear interest at Canadian LIBOR plus 1.125% or Canadian prime rate plus 0.125%. Distributions from Greenfield LP were $9 million during both the three and six months ended June 30, 2012, and $2 million during both the three and six months ended June 30, 2011.
Whitby — Whitby is a limited partnership between certain subsidiaries of ours 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. Distributions from Whitby were $7 million during both the three and six months ended June 30, 2012, and $4 million during both the three and six months ended June 30, 2011.
Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California which achieved COD on May 3, 2010) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.
Debt
Debt Disclosure [Text Block]
Debt
At June 30, 2012 and December 31, 2011, our debt was as follows (in millions):
 
June 30, 2012

December 31, 2011
First Lien Notes
$
5,892

 
$
5,892

Project financing, notes payable and other
1,865

 
1,691

First Lien Term Loans
1,638

 
1,646

CCFC Notes
975

 
972

Capital lease obligations
221

 
224

Total debt
10,591

 
10,425

Less: Current maturities
103

 
104

Debt, net of current portion
$
10,488

 
$
10,321

First Lien Notes
Our First Lien Notes are summarized in the table below (in millions):
 
June 30, 2012
 
December 31, 2011
2017 First Lien Notes
$
1,200

 
$
1,200

2019 First Lien Notes
400

 
400

2020 First Lien Notes
1,092

 
1,092

2021 First Lien Notes
2,000

 
2,000

2023 First Lien Notes
1,200

 
1,200

Total First Lien Notes
$
5,892

 
$
5,892

Our First Lien Notes are secured equally and ratably with indebtedness incurred under our Corporate Revolving Facility and First Lien Term Loans, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors' existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors' other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes.
Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:
•
incur or guarantee additional first lien indebtedness;
•
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
•
enter into sale and leaseback transactions;
•
create or incur liens; and
•
consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.
First Lien Term Loans
Our First Lien Term Loans provide for a senior secured term loan facility and bear interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the First Lien Term Loans credit agreements), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%.
An aggregate amount equal to 0.25% of the aggregate principal amount of the First Lien Term Loans will be payable at the end of each quarter with the remaining balance payable on the maturity date (April 1, 2018). We may elect from time to time to convert all or a portion of the First Lien Term Loans from initial LIBOR rate loans to base rate loans or vice versa. In addition, we may at any time, and from time to time, prepay the First Lien Term Loans, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent. We may elect to extend the maturity of any term loans under the First Lien Term Loans, in whole or in part subject to approval from those lenders holding such term loans. The First Lien Term Loans are subject to certain qualifications and exceptions, similar to our First Lien Notes.
If a change of control triggering event occurs, the Company shall notify the administrative agent in writing and shall make an offer to prepay the entire principal amount of the First Lien Term Loans outstanding within thirty days after the date of such change of control triggering event.
In connection with the First Lien Term Loans, the Company and its subsidiaries (subject to certain exceptions) have made certain representations and warranties and are required to comply with various affirmative and negative covenants. The First Lien Term Loans are subject to customary events of default included in financing transactions, including, among others, failure to make payments when due, certain defaults under other material indebtedness, breach of certain covenants, breach of certain representations and warranties, involuntary or voluntary bankruptcy, and material judgments. If an event of default arises from certain events of bankruptcy or insolvency, all amounts outstanding under the First Lien Term Loans will become due and payable immediately without further action or notice. If other events of default arise (as defined in the Credit Agreement) and are continuing, the lenders holding more than 50% of the outstanding First Lien Term Loans (as defined in the Credit Agreement) may declare all the First Lien Term Loans outstanding to be due and payable immediately.
Russell City Project Debt 
On June 24, 2011, we, through our indirect, partially owned subsidiary Russell City Energy Company, LLC, closed on our approximately $845 million Russell City Project Debt to finance construction of Russell City Energy Center, a 619 MW natural gas-fired, combined-cycle power plant under construction located in Hayward, California. The Russell City Project Debt is comprised of a $700 million construction loan facility, an approximately $77 million project letter of credit facility and a $68 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At June 30, 2012, approximately $414 million had been drawn under the construction loan and approximately $61 million of letters of credit were issued under the letter of credit facilities. Calpine's pro rata share would be 75% and the pro rata share related to the noncontrolling interest would be 25%.
Los Esteros Project Debt
On August 23, 2011, we, through our indirect, wholly owned subsidiary Los Esteros Critical Energy Facility, LLC, closed on our $373 million Los Esteros Project Debt to finance the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle power plant to a 309 MW combined-cycle generation power plant. The upgrade will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. The Los Esteros Project Debt is comprised of a $305 million construction loan facility, an approximately $38 million project letter of credit facility and an approximately $30 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At June 30, 2012, approximately $139 million had been drawn under the construction loan and approximately $30 million of letters of credit were issued under the letter of credit facilities.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
Corporate Revolving Facility
$
385

 
$
440

CDHI
256

 
193

Various project financing facilities
130

 
130

Total
$
771

 
$
763


The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 2.00% to 2.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers' Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 3.00% to 3.25%. Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.50% to 0.75% on the unused amount of commitments under the Corporate Revolving Facility.
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures December 10, 2015.
The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors' other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.
CDHI
We also have a letter of credit facility related to CDHI. On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to January 2, 2016.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The following table details the fair values and carrying values of our debt instruments at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
6,340

 
$
5,892

 
$
6,219

 
$
5,892

Project financing, notes payable and other(1)
1,667

 
1,705

 
1,467

 
1,504

First Lien Term Loans
1,630

 
1,638

 
1,615

 
1,646

CCFC Notes
1,085

 
975

 
1,070

 
972

Total
$
10,722

 
$
10,210

 
$
10,371

 
$
10,014

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

On January 1, 2012, we adopted Accounting Standards Update 2011-04 "Fair Value Measurement" which requires the categorization by level of the fair value hierarchy for items not measured at fair value on our Consolidated Condensed Balance Sheets but for which fair value is required to be disclosed. We measure the fair value of our First Lien Notes, First Lien Term Loans and CCFC Notes using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
Assets and Liabilities with Recurring Fair Value Measurements
Assets and Liabilities with Recurring Fair Value Measurements
Assets and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Our cash equivalents are classified within level 1 of the fair value hierarchy.
Margin Deposits and Margin Deposits Held by Us Posted by Our Counterparties — Margin deposits and margin deposits held by us posted by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits held by us posted 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); market price levels, primarily for power and natural gas; our credit standing and that of our counterparties; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of natural gas swaps, futures and options traded on the NYMEX.
Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are primarily industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our or our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. In cases where there is no corroborating market information available to support significant model inputs, we initially use the transaction price as the best estimate of fair value. 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.
At June 30, 2012, the derivative instruments classified as level 3 primarily included longer term OTC traded commodity contracts extending through 2014. These contracts are classified as level 3 as the contract terms exceed the period for which liquid market rate information is available. As such, the fair value of each contract incorporates extrapolation assumptions made in the determination of the market price for future delivery periods in which applicable commodity prices were either not observable or lacked corroborative market data. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices, however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2012.
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
June 30, 2012
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input(s)
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
(8
)
 
Discounted cash flow
 
Market price (per MWh)
 
$19.30 — $160.75/MWh

The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, by level within the fair value hierarchy. 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.
 
Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2012
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
723

 
$
—

 
$
—

 
$
723

Margin deposits
262

 
—

 
—

 
262

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
923

 
—

 
—

 
923

Commodity forward contracts(2)
—

 
252

 
26

 
278

Interest rate swaps
—

 
6

 
—

 
6

Total assets
$
1,908

 
$
258

 
$
26

 
$
2,192

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
45

 
$
—

 
$
—

 
$
45

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
745

 
—

 
—

 
745

Commodity forward contracts(2)
—

 
541

 
36

 
577

Interest rate swaps
—

 
197

 
—

 
197

Total liabilities
$
790

 
$
738

 
$
36

 
$
1,564


 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2011
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,415

 
$
—

 
$
—

 
$
1,415

Margin deposits
140

 
—

 
—

 
140

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,043

 
—

 
—

 
1,043

Commodity forward contracts(2)
—

 
74

 
37

 
111

Interest rate swaps
—

 
10

 
—

 
10

Total assets
$
2,598

 
$
84

 
$
37

 
$
2,719

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
34

 
$
—

 
$
—

 
$
34

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
899

 
—

 
—

 
899

Commodity forward contracts(2)
—

 
184

 
20

 
204

Interest rate swaps
—

 
320

 
—

 
320

Total liabilities
$
933

 
$
504

 
$
20

 
$
1,457

___________
(1)
As of June 30, 2012 and December 31, 2011, we had cash equivalents of $574 million and $1,249 million included in cash and cash equivalents and $149 million and $166 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
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,
 
2012
 
2011
 
2012
 
2011
Balance, beginning of period
$
17

 
$
12

 
$
17

 
$
30

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
Included in net loss:
 
 
 
 
 
 
 
Included in operating revenues(1)
(24
)
 
10

 
(17
)
 
6

Included in fuel and purchased energy expense(2)
2

 
1

 
—

 
—

Included in OCI
—

 
4

 
4

 
5

Purchases, issuances and settlements:
 
 
 
 
 
 
 
Purchases
1

 
1

 
1

 
1

Issuances
(1
)
 
—

 
(1
)
 
—

Settlements
(5
)
 
(7
)
 
(11
)
 
(21
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
Transfers into level 3(4)
—

 
—

 
—

 
—

Transfers out of level 3(5)
—

 
—

 
(3
)
 
—

Balance, end of period
$
(10
)
 
$
21

 
$
(10
)
 
$
21

Change in unrealized gains (losses) relating to instruments still held at end of period
$
(22
)
 
$
11

 
$
(17
)
 
$
7

___________
(1)
For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(3)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into/out of level 1 during the three and six months ended June 30, 2012 and 2011.
(4)
There were no transfers out of level 2 into level 3 for the three and six months ended June 30, 2012 and 2011.
(5)
We had $3 million of transfers out of level 3 into level 2 for the six months ended June 30, 2012. There were no transfers out of level 3 for the three months ended June 30, 2012 and for the three and six months ended June 30, 2011.
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 and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of June 30, 2012, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 11 years.
As of June 30, 2012 and December 31, 2011, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
June 30, 2012
 
December 31, 2011
Power (MWh)
 
(21
)
 
(21
)
Natural gas (MMBtu)
 
(68
)
 
(200
)
Interest rate swaps(1)
 
$
1,592

 
$
5,639

____________
(1)
Approximately $4.1 billion at December 31, 2011 was related to hedges of our First Lien Credit Facility's variable rate debt that was converted to fixed rate debt. On March 26, 2012, we terminated the interest rate swaps formerly hedging our First Lien Credit Facility.
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, 2012, was $339 million for which we have posted collateral of $244 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, Corporate Revolving Facility and First Lien Term Loans. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $5 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. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election will be reflected in earnings and could create more volatility in our earnings. The fair value of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting will be reclassified to earnings in future periods as the related economic transactions affect earnings or if the forecasted transaction becomes probable of not occurring. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We report the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and swaps), fuel and purchased energy expense (for natural gas contracts and swaps) and interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas and interest rate 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 derivatives not designated as hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts, swaps and options) and interest expense (for interest rate swaps except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — In January 2011, we repaid approximately $1.2 billion of our First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps hedging the scheduled variable interest payments. With the repayment of these First Lien Credit Facility term loans, unrealized losses of approximately $91 million in AOCI related to the interest rate swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into earnings as an additional loss on interest rate derivatives during the first quarter of 2011. We have presented the reclassification of unrealized losses from AOCI into earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as loss on interest rate derivatives on our Consolidated Condensed Statements of Operations. On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Condensed Statements of Operations for the six months ended June 30, 2012 and approximately $142 million reflected the realization of losses recorded in prior periods.
Derivatives Included on Our Consolidated Condensed Balance Sheet
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
  
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
—

 
$
1,049

 
$
1,049

Long-term derivative assets
6

 
152

 
158

Total derivative assets
$
6

 
$
1,201

 
$
1,207

 
 
 
 
 
 
Current derivative liabilities
$
31

 
$
1,212

 
$
1,243

Long-term derivative liabilities
166

 
110

 
276

Total derivative liabilities
$
197

 
$
1,322

 
$
1,519

Net derivative assets (liabilities)
$
(191
)
 
$
(121
)
 
$
(312
)
 
December 31, 2011
 
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
—

 
$
1,051

 
$
1,051

Long-term derivative assets
10

 
103

 
113

Total derivative assets
$
10

 
$
1,154

 
$
1,164

 
 
 
 
 
 
Current derivative liabilities
$
166

 
$
978

 
$
1,144

Long-term derivative liabilities
154

 
125

 
279

Total derivative liabilities
$
320

 
$
1,103

 
$
1,423

Net derivative assets (liabilities)
$
(310
)
 
$
51

 
$
(259
)


 
June 30, 2012
 
December 31, 2011
 
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(1):
 
 
 
 
 
 
 
Interest rate swaps
$
6

 
$
176

 
$
10

 
$
149

Commodity instruments
28

 
4

 
51

 
18

Total derivatives designated as cash flow hedging instruments
$
34

 
$
180

 
$
61

 
$
167

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$
—

 
$
21

 
$
—

 
$
171

Commodity instruments
1,173

 
1,318

 
1,103

 
1,085

Total derivatives not designated as hedging instruments
$
1,173

 
$
1,339

 
$
1,103

 
$
1,256

Total derivatives
$
1,207

 
$
1,519

 
$
1,164

 
$
1,423

____________
(1)
Includes accumulated fair value of derivative instruments as of the date hedge accounting was discontinued, net of amortized fair value for settlement periods which have transpired.
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 mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized gain (loss)
 
 
 
 
 
 
 
Interest rate swaps
$
—

 
$
(60
)
 
$
(157
)
 
$
(106
)
Commodity derivative instruments
94

 
42

 
212

 
52

Total realized gain (loss)
$
94

 
$
(18
)
 
$
55

 
$
(54
)
 
 
 
 
 
 
 
 
Unrealized gain (loss)(1)
 
 
 
 
 
 
 
Interest rate swaps
$
3

 
$
24

 
$
149

 
$
(38
)
Commodity derivative instruments
(346
)
 
26

 
(268
)
 
(39
)
Total unrealized gain (loss)
$
(343
)
 
$
50

 
$
(119
)
 
$
(77
)
Total mark-to-market activity, net
$
(249
)
 
$
32

 
$
(64
)
 
$
(131
)
___________
(1)
In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized and unrealized gain (loss)
 
 
 
 
 
 
 
Power contracts included in operating revenues
$
(272
)
 
$
48

 
$
(180
)
 
$
(9
)
Natural gas contracts included in fuel and purchased energy expense
20

 
20

 
124

 
22

Interest rate swaps included in interest expense
3

 
1

 
6

 
2

Loss on interest rate derivatives
—

 
(37
)
 
(14
)
 
(146
)
Total mark-to-market activity, net
$
(249
)
 
$
32

 
$
(64
)
 
$
(131
)

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,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(1)
 
Gain (Loss) Reclassified from
AOCI into Income  (Ineffective
Portion)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Interest rate swaps
$
(35
)
 
$
(9
)
 
$
(8
)
(2) 
$
(22
)
(2) 
$
—

 
$
(1
)
Commodity derivative instruments
(13
)
 
(39
)
 
12

(3) 
53

(3) 
—

 
1

Total
$
(48
)
 
$
(48
)
 
$
4

 
$
31

  
$
—

 
$
—


 
Six Months Ended June 30,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(1)
 
Gain (Loss) Reclassified from
AOCI into Income  (Ineffective
Portion)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Interest rate swaps
$
(34
)
 
$
94

 
$
(15
)
(4) 
$
(123
)
(4) 
$
—

 
$
(1
)
Commodity derivative instruments
(14
)
 
(36
)
 
29

(3) 
79

(3) 
2

 
1

Total
$
(48
)
 
$
58

 
$
14

 
$
(44
)
  
$
2

 
$
—

____________
(1)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $216 million and $172 million at June 30, 2012 and December 31, 2011, respectively.
(2)
Reclassification of losses from OCI to earnings consisted of $8 million and $7 million from the reclassification of interest rate contracts due to settlement for the three months ended June 30, 2012 and 2011, respectively, and $15 million in losses from terminated interest rate contracts due to repayment of project debt in June 2011 for the three months ended June 30, 2011.
(3)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statement of Operations.
(4)
Reclassification of losses from OCI to earnings consisted of $15 million and $17 million from the reclassification of interest rate contracts due to settlement for the six months ended June 30, 2012 and 2011, respectively, $15 million in losses from terminated interest rate contracts due to repayment of project debt in June 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans for the six months ended June 30, 2011.
As a result of our election to discontinue hedge accounting treatment for our commodity derivatives accounted for as cash flow hedges, the fair value of our commodity derivative instruments residing in AOCI will be reclassified to earnings over the next six months as the related hedged transactions affect earnings. We estimate that pre-tax net losses of $6 million (comprised of amounts related to interest rate swaps and the commodity hedges previously discussed) would be reclassified from AOCI into earnings 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
Use of Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate swap agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.
The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
Margin deposits(1)
$
262

 
$
140

Natural gas and power prepayments
37

 
42

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
299

 
$
182

 
 
 
 
Letters of credit issued
$
561

 
$
581

First priority liens under power and natural gas agreements
1

 
1

First priority liens under interest rate swap agreements
203

 
318

Total letters of credit and first priority liens with our counterparties
$
765

 
$
900

 
 
 
 
Margin deposits held by us posted by our counterparties(1)(3)
$
45

 
$
34

Letters of credit posted with us by our counterparties
1

 
—

Total margin deposits and letters of credit posted with us by our counterparties
$
46

 
$
34

___________
(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.
(2)
At June 30, 2012 and December 31, 2011, $275 million and $162 million, respectively, were included in margin deposits and other prepaid expense and $24 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.
Income Taxes
Income Taxes
Income Taxes
Income Tax Expense (Benefit)

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our imputed tax rates for the periods indicated (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Income tax expense (benefit)
$
(52
)
 
$
18

 
$
(58
)
 
$
(65
)
(1 
) 
Imputed tax rate
14
%
 
(35
)%
 
15
%
 
15
%
 
_________
(1)
Includes a tax benefit of approximately $76 million related to the election to consolidate our CCFC and Calpine groups for federal income tax reporting purposes for the six months ended June 30, 2011.
Accounting for Income Taxes
Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax (benefit) to continuing operations due to current OCI gains with an offsetting amount recognized in OCI. The following table details the effects of our intraperiod tax allocations for the three and six months ended June 30, 2012 and 2011 (in millions).
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Intraperiod tax allocation expense (benefit) included in continuing operations
$
2

 
$
18

 
$
4

 
$
(16
)
Intraperiod tax allocation expense (benefit) included in OCI
$
(2
)
 
$
(18
)
 
$
(4
)
 
$
16


NOL Carryforwards — Under federal income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. We experienced an ownership change on the Effective Date as a result of the cancellation of our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this ownership change and the resulting annual limitations are not expected to result in the expiration of our NOL carryforwards if we are able to generate sufficient future taxable income within the carryforward periods. When considering our cumulative annual Section 382 limitations, in addition to our post-Effective Date NOLs that are not limited, our total unrestricted NOLs were approximately $6.3 billion at December 31, 2011. If a subsequent ownership change were to occur as a result of future transactions in our common stock, accompanied by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited.
Under state income tax laws, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. During 2011, we analyzed the effect of our change in ownership on the Effective Date for each of our significant states to determine the amount of our NOL limitation. The analysis determined that $640 million of our state NOLs are expected to expire unutilized as a result of statutory limitations on the use of some of our pre-emergence date NOLs as of the Effective Date or the cessation of business operations in various tax jurisdictions. We reduced our deferred tax asset for state NOLs that we are unable to utilize and made an equal reduction in our valuation allowance in 2011. The result did not have an impact on our income tax expense in 2011. As we had estimated, approximately $50 million of our state NOLs are expected to expire unutilized during 2012 as a result of statutory state limitations relating to the time period NOLs can be carried forward, and accordingly, we reduced our deferred tax asset and made an equal reduction in our valuation allowance. The reduction did not have an impact to our income tax expense in 2012. We will likely make future annual adjustments to our state NOLs that have expired or are limited under Section 382 of the IRC.
To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation requires our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock if, prior to February 1, 2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of approximately $8.6 billion (in each case, as defined in and calculated pursuant to our amended and restated certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to our equity for purposes of Section 382 of the IRC. We believe as of the filing of this Report, an ownership change of 25 percentage points has occurred; however, we have not experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization. Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the foregoing events were to occur together and our Board of Directors was to elect to impose them, they could become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from occurring. Unless extended by a vote of the shareholders, the ability of the Board of Directors to impose transfer restrictions on our common stock terminates on January 31, 2013.
Should our Board of Directors elect to impose these restrictions, it will have the authority and discretion to determine and establish the definitive terms of the transfer restrictions, provided that the transfer restrictions apply to purchases by owners of 5% or more of our common stock, including any owners who would become owners of 5% or more of our common stock via such purchase. The transfer restrictions will not apply to the disposition of shares provided they are not purchased by a 5% or more owner.
Income Tax Audits — We remain subject to various audits and reviews by taxing authorities; however, we do not expect these will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to U.S. Internal Revenue Service examination regardless of when the NOLs occurred. Due to significant NOLs, any adjustment of state returns or federal returns from 2007 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.
Canadian Tax Audits — In September 2009, we received notice from the Canadian Revenue Authority, or CRA, of their intent to conduct a limited scope income tax audit on four of our Canadian subsidiaries for the tax years 2005 through 2008. The CRA concluded that there were no adjustments on two of the entities, but further review was required on the remaining two subsidiaries. On April 23, 2012, the remaining two subsidiaries received proposed adjustments from the CRA regarding our tax transfer pricing positions. On June 21, 2012, we met with the CRA to discuss their proposed adjustments and provide clarification where we believed it was needed. In July 2012, we received additional questions from the CRA as a result of our meeting and will respond by the agreed date of September 15, 2012.
We continue to evaluate the proposed adjustments; however, based on our preliminary analysis, we believe that our transfer pricing tax positions and policies are appropriate, and we intend to challenge the CRA's proposed adjustments. If we are unsuccessful in our challenge, any adjustment to Canadian taxable income would first be offset against any existing NOLs that are available; however, we do not believe any reassessment resulting in an adjustment to taxable income which is greater than our existing NOLs, or including interest or penalties which cannot be offset by existing NOLs, would have a material adverse effect on our financial condition, results of operations or cash flows.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, since our emergence from Chapter 11, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At June 30, 2012, we had unrecognized tax benefits of $84 million. If recognized, $38 million of our unrecognized tax benefits could impact the annual effective tax rate and $46 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $22 million for income tax matters at June 30, 2012. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. The amount of unrecognized tax benefits at June 30, 2012 increased by $9 million from December 31, 2011 primarily related to prior year tax positions. We believe it is reasonably possible that a decrease within the range of approximately nil and $23 million in unrecognized tax benefits could occur within the next 12 months primarily related to state and foreign tax issues.
Earnings (Loss) per Share
Earnings (Loss) per Share
Loss per Share
Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled and the issuance of 485 million new shares of reorganized Calpine Corporation common stock was authorized to resolve allowed unsecured claims. A portion of the 485 million authorized shares was immediately distributed, and the remainder was reserved for distribution to holders of certain disputed claims that, although allowed as of the Effective Date, were unresolved. In June 2011, we settled the largest remaining claim outstanding and began the process of distributing the balance of the reserved shares, which was completed during the third quarter of 2011, pursuant to our Plan of Reorganization. Accordingly, although the reserved shares were not issued and outstanding for the three and six months ended June 30, 2011, all conditions of distribution had been met for these reserved shares as of the Effective Date, and such shares are considered issued and are included in our calculation of weighted average shares outstanding. We also include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding.
As we incurred a net loss for the three and six months ended June 30, 2012 and 2011, diluted loss per share for these 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. We excluded the following items from diluted loss per common share for the three and six months ended June 30, 2012 and 2011, because they were anti-dilutive (shares in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Share-based awards
13,920

 
15,309

 
15,236

 
15,131

Stock-Based Compensation
Stock-Based Compensation
Stock-Based Compensation
Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting options which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At June 30, 2012, there were 567,000 and 27,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively.
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views one three-year option grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of stock options granted. The first sub-grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year option grant with cliff vesting is viewed as one grant vesting over three years.
Stock-based compensation expense recognized was $7 million for both the three months ended June 30, 2012 and 2011, and $13 million and $12 million for the six months ended June 30, 2012 and 2011, 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, 2012 and 2011. At June 30, 2012, there was unrecognized compensation cost of $10 million related to options, $25 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 1.1 years for options, 1.7 years for restricted stock and 0.9 years for restricted stock units. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2012, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2011
17,665,902

 
$
17.32

 
4.8
 
$
26

Granted
888,407

 
$
15.33

 
 
 
 
Exercised
159,700

 
$
16.07

 
 
 
 
Forfeited
43,447

 
$
11.76

 
 
 
 
Expired
74,300

 
$
17.74

 
 
 
 
Outstanding — June 30, 2012
18,276,862

 
$
17.24

 
4.5
 
$
28

Exercisable — June 30, 2012
8,835,451

 
$
18.69

 
4.3
 
$
7

Vested and expected to vest – June 30, 2012
17,866,052

 
$
17.31

 
4.4
 
$
27


The total intrinsic value of our employee stock options exercised was not significant for both the six months ended June 30, 2012 and 2011. The total cash proceeds received from our employee stock options exercised was $3 million and nil for the six months ended June 30, 2012 and 2011, respectively.
The fair value of options granted during the six months ended June 30, 2012 and 2011, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
2012
 
2011
 
Expected term (in years)(1)
6.5

 
6.5

 
Risk-free interest rate(2)
1.6

%
2.7 – 3.2

%
Expected volatility(3)
30.0 – 30.5

%
31.2 – 31.7

%
Dividend yield(4)
—

 
—

 
Weighted average grant-date fair value (per option)
$
5.18

 
$
5.48

 
___________
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3)
Volatility calculated using the implied volatility of our exchange traded stock options.
(4)
We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future.
No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2012, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2011
3,510,358

 
$
12.10

Granted
1,554,311

 
$
15.38

Forfeited
135,638

 
$
13.33

Vested
1,042,095

 
$
10.08

Nonvested — June 30, 2012
3,886,936

 
$
13.89


The total fair value of our restricted stock that vested during the six months ended June 30, 2012 and 2011, was approximately $19 million and $7 million, respectively.
Commitments and Contingencies
Commitments and Contingencies
Commitments and Contingencies
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings will have a material adverse effect on our financial condition, results of operations or cash flows.
On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
Environmental Matters
We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material impact on our financial condition, results of operations or cash flows or that would significantly change our operations.
Segment and Significant Customer Information
Segment and Significant Customer Information
Segment Information
We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At June 30, 2012, our reportable segments were West (including geothermal), Texas, North (including Canada) and Southeast. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.
Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).
 
Three Months Ended June 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
258

 
$
188

 
$
269

 
$
164

 
$
—

 
$
879

Intersegment revenues
1

 
41

 
2

 
(6
)
 
(38
)
 
—

Total operating revenues
$
259

 
$
229

 
$
271

 
$
158

 
$
(38
)
 
$
879

Commodity Margin(1)
$
210

 
$
145

 
$
181

 
$
73

 
$
—

 
$
609

Add: Mark-to-market commodity activity, net and other(2)(3)
(76
)
 
(217
)
 
(3
)
 
(42
)
 
(6
)
 
(344
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
112

 
72

 
58

 
36

 
(7
)
 
271

Depreciation and amortization expense
49

 
34

 
34

 
22

 
(1
)
 
138

Sales, general and other administrative expense
6

 
13

 
8

 
7

 
1

 
35

Other operating expenses(4)
9

 
1

 
6

 
2

 
1

 
19

(Income) from unconsolidated investments in power plants
—

 
—

 
(5
)
 
—

 
—

 
(5
)
Income (loss) from operations
(42
)
 
(192
)
 
77

 
(36
)
 
—

 
(193
)
Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
182

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
6

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(381
)

 
Three Months Ended June 30, 2011
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
466

 
$
646

 
$
324

 
$
197

 
$
—

 
$
1,633

Intersegment revenues
1

 
5

 
5

 
40

 
(51
)
 
—

Total operating revenues
$
467

 
$
651

 
$
329

 
$
237

 
$
(51
)
 
$
1,633

Commodity Margin(1)
$
236

 
$
128

 
$
184

 
$
59

 
$
—

 
$
607

Add: Mark-to-market commodity activity, net and other(2)(3)
11

 
27

 
(5
)
 
—

 
(9
)
 
24

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
116

 
63

 
47

 
41

 
(6
)
 
261

Depreciation and amortization expense
42

 
35

 
33

 
22

 
(1
)
 
131

Sales, general and other administrative expense
8

 
13

 
6

 
6

 
1

 
34

Other operating expenses(4)
11

 
3

 
9

 
2

 
(5
)
 
20

Loss from unconsolidated investments in power plants
—

 
—

 
2

 
—

 
—

 
2

Income (loss) from operations
70

 
41

 
82

 
(12
)
 
2

 
183

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
190

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
37

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
8

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(52
)

 
Six Months Ended June 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
674

 
$
544

 
$
567

 
$
330

 
$
—

 
$
2,115

Intersegment revenues
5

 
61

 
5

 
16

 
(87
)
 
—

Total operating revenues
$
679

 
$
605

 
$
572

 
$
346

 
$
(87
)
 
$
2,115

Commodity Margin(1)
$
418

 
$
254

 
$
325

 
$
129

 
$
—

 
$
1,126

Add: Mark-to-market commodity activity, net and other(2)(5)
(40
)
 
(183
)
 
9

 
(32
)
 
(14
)
 
(260
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
193

 
140

 
103

 
69

 
(13
)
 
492

Depreciation and amortization expense
99

 
69

 
67

 
45

 
(2
)
 
278

Sales, general and other administrative expense
14

 
24

 
14

 
15

 
1

 
68

Other operating expenses(4)
20

 
3

 
15

 
3

 
(1
)
 
40

(Income) from unconsolidated investments in power plants
—

 
—

 
(14
)
 
—

 
—

 
(14
)
Income (loss) from operations
52


(165
)

149


(35
)

1

 
2

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
364

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
14

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
20

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(396
)

 
Six Months Ended June 30, 2011
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,065

 
$
1,096

 
$
595

 
$
376

 
$
—

 
$
3,132

Intersegment revenues
4

 
10

 
13

 
85

 
(112
)
 
—

Total operating revenues
$
1,069

 
$
1,106

 
$
608

 
$
461

 
$
(112
)
 
$
3,132

Commodity Margin(1)
$
469

 
$
195

 
$
319

 
$
113

 
$
—

 
$
1,096

Add: Mark-to-market commodity activity, net and other(2)(5)
16

 
(33
)
 
(1
)
 
(4
)
 
(15
)
 
(37
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
203

 
143

 
92

 
74

 
(13
)
 
499

Depreciation and amortization expense
88

 
65

 
66

 
45

 
(2
)
 
262

Sales, general and other administrative expense
19

 
23

 
12

 
11

 
1

 
66

Other operating expenses(4)
19

 
3

 
16

 
3

 
(3
)
 
38

(Income) from unconsolidated investments in power plants
—

 
—

 
(7
)
 
—

 
—

 
(7
)
Income (loss) from operations
156


(72
)

139


(24
)

2

 
201

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
378

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
146

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
108

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(431
)
_________
(1)
Our North segment includes Commodity Margin related to Riverside Energy Center, LLC of $24 million and $22 million for three months ended June 30, 2012 and 2011, respectively, and $32 million and $31 million for the six months ended June 30, 2012 and 2011, respectively.
(2)
Mark-to-market commodity activity represents the change in the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations. The increase in unrealized mark-to-market losses for the three and six months ended June 30, 2012, was primarily driven by the impact of a near term increase in forward power prices and corresponding Market Heat Rate expansion in the ERCOT region during the last several days of June 2012.
(3)
Includes $(1) million and $4 million of lease levelization and $3 million and $1 million of amortization expense for the three months ended June 30, 2012 and 2011, respectively.
(4)
Excludes $2 million of RGGI compliance and other environmental costs for both the three months ended June 30, 2012 and 2011, and $5 million and $4 million for the six months ended June 30, 2012 and 2011, respectively, which are components of Commodity Margin.
(5)
Includes $(9) million and $4 million of lease levelization and $7 million and $1 million of amortization expense for the six months ended June 30, 2012 and 2011, respectively.
Summary of Significant Accounting Policies (Policies)
Derivatives, Policy [Policy Text Block] 
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election will be reflected in earnings and could create more volatility in our earnings. The fair value of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting will be reclassified to earnings in future periods as the related economic transactions affect earnings or if the forecasted transaction becomes probable of not occurring. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We report the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and swaps), fuel and purchased energy expense (for natural gas contracts and swaps) and interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas and interest rate 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 derivatives not designated as hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts, swaps and options) and interest expense (for interest rate swaps except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — In January 2011, we repaid approximately $1.2 billion of our First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps hedging the scheduled variable interest payments. With the repayment of these First Lien Credit Facility term loans, unrealized losses of approximately $91 million in AOCI related to the interest rate swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into earnings as an additional loss on interest rate derivatives during the first quarter of 2011. We have presented the reclassification of unrealized losses from AOCI into earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as loss on interest rate derivatives on our Consolidated Condensed Statements of Operations. On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Condensed Statements of Operations for the six months ended June 30, 2012 and approximately $142 million reflected the realization of losses recorded in prior periods.
Consolidation 
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, 2011, included in our 2011 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, intraperiod provisions for income taxes computed in accordance with U.S. GAAP, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.
Use of Estimates, Policy [Policy Text Block] 
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 
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At June 30, 2012 and December 31, 2011, we had cash and cash equivalents of $178 million and $306 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash 
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.
Inventory 
Inventory — At June 30, 2012 and December 31, 2011, we had inventory of $262 million and $294 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Commitments and Contingencies, Policy [Policy Text Block] 
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.
Summary of Significant Accounting Policies (Tables)
Property, Plant and Equipment [Table Text Block] 
Property, Plant and Equipment, Net — At June 30, 2012 and December 31, 2011, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
June 30, 2012
 
December 31, 2011
Buildings, machinery and equipment
$
15,154

 
$
15,074

Geothermal properties
1,199

 
1,163

Other
157

 
156

 
16,510

 
16,393

Less: Accumulated depreciation
4,405

 
4,158

 
12,105

 
12,235

Land
90

 
91

Construction in progress
914

 
693

Property, plant and equipment, net
$
13,109

 
$
13,019

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block] 
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements related to power plants under construction, at June 30, 2012, are as follows (in millions):
2012
$
285

2013
527

2014
465

2015
481

2016
396

Thereafter
2,312

Total
$
4,466

 
 
Schedule of Components of Restricted Cash 
The table below represents the components of our restricted cash as of June 30, 2012 and December 31, 2011 (in millions):

 
June 30, 2012
 
December 31, 2011
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service(1)
$
16

 
$
42

 
$
58

 
$
11

 
$
42

 
$
53

Rent reserve
7

 
—

 
7

 
—

 
—

 
—

Construction/major maintenance
47

 
2

 
49

 
33

 
10

 
43

Security/project/insurance
54

 
5

 
59

 
79

 
—

 
79

Other
—

 
2

 
2

 
16

 
3

 
19

Total
$
124

 
$
51

 
$
175

 
$
139

 
$
55

 
$
194

___________
(1)
At both June 30, 2012 and December 31, 2011, amounts restricted for debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.
Variable Interest Entities and Unconsolidated Investments (Tables)
Schedule of Equity Method Investments 
At June 30, 2012 and December 31, 2011, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of June 30, 2012
 
June 30, 2012
 
December 31, 2011
Greenfield LP
50%
 
$
69

 
$
72

Whitby
50%
 
7

 
8

Total investments
 
 
$
76

 
$
80

Income/Loss from Unconsolidated Investments in Power Plants and Distributions 
Our equity interest in the net income (loss) from Greenfield LP and Whitby for the three and six months ended June 30, 2012 and 2011 is recorded in (income) loss from unconsolidated investments in power plants. The following table sets forth details of our (income) loss from unconsolidated investments in power plants for the periods indicated (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Greenfield LP
$
(2
)
 
$
4

 
$
(8
)
 
$
(1
)
Whitby
(3
)
 
(2
)
 
(6
)
 
(6
)
Total
$
(5
)
 
$
2

 
$
(14
)
 
$
(7
)

Debt (Tables)
Schedule of Long-term Debt Instruments 
t June 30, 2012 and December 31, 2011, our debt was as follows (in millions):
 
June 30, 2012

December 31, 2011
First Lien Notes
$
5,892

 
$
5,892

Project financing, notes payable and other
1,865

 
1,691

First Lien Term Loans
1,638

 
1,646

CCFC Notes
975

 
972

Capital lease obligations
221

 
224

Total debt
10,591

 
10,425

Less: Current maturities
103

 
104

Debt, net of current portion
$
10,488

 
$
10,321

First Lien Notes 
Our First Lien Notes are summarized in the table below (in millions):
 
June 30, 2012
 
December 31, 2011
2017 First Lien Notes
$
1,200

 
$
1,200

2019 First Lien Notes
400

 
400

2020 First Lien Notes
1,092

 
1,092

2021 First Lien Notes
2,000

 
2,000

2023 First Lien Notes
1,200

 
1,200

Total First Lien Notes
$
5,892

 
$
5,892

Schedule of Line of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
Corporate Revolving Facility
$
385

 
$
440

CDHI
256

 
193

Various project financing facilities
130

 
130

Total
$
771

 
$
763


Schedule of Carrying Values and Estimated Fair Values of Debt Instruments 
The following table details the fair values and carrying values of our debt instruments at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
First Lien Notes
$
6,340

 
$
5,892

 
$
6,219

 
$
5,892

Project financing, notes payable and other(1)
1,667

 
1,705

 
1,467

 
1,504

First Lien Term Loans
1,630

 
1,638

 
1,615

 
1,646

CCFC Notes
1,085

 
975

 
1,070

 
972

Total
$
10,722

 
$
10,210

 
$
10,371

 
$
10,014

____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
Assets and Liabilities with Recurring Fair Value Measurements (Tables)
Fair Value Inputs, Liabilities, Quantitative Information [Table Text Block] 
The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2012.
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
June 30, 2012
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input(s)
 
Range
 
 
(in millions)
 
 
 
 
 
 
Physical Power
 
$
(8
)
 
Discounted cash flow
 
Market price (per MWh)
 
$19.30 — $160.75/MWh
Fair Value, Measurement Inputs, Disclosure 
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, by level within the fair value hierarchy. 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.
 
Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2012
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
723

 
$
—

 
$
—

 
$
723

Margin deposits
262

 
—

 
—

 
262

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
923

 
—

 
—

 
923

Commodity forward contracts(2)
—

 
252

 
26

 
278

Interest rate swaps
—

 
6

 
—

 
6

Total assets
$
1,908

 
$
258

 
$
26

 
$
2,192

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
45

 
$
—

 
$
—

 
$
45

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
745

 
—

 
—

 
745

Commodity forward contracts(2)
—

 
541

 
36

 
577

Interest rate swaps
—

 
197

 
—

 
197

Total liabilities
$
790

 
$
738

 
$
36

 
$
1,564


 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2011
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,415

 
$
—

 
$
—

 
$
1,415

Margin deposits
140

 
—

 
—

 
140

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,043

 
—

 
—

 
1,043

Commodity forward contracts(2)
—

 
74

 
37

 
111

Interest rate swaps
—

 
10

 
—

 
10

Total assets
$
2,598

 
$
84

 
$
37

 
$
2,719

Liabilities:
 
 
 
 
 
 
 
Margin deposits held by us posted by our counterparties
$
34

 
$
—

 
$
—

 
$
34

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
899

 
—

 
—

 
899

Commodity forward contracts(2)
—

 
184

 
20

 
204

Interest rate swaps
—

 
320

 
—

 
320

Total liabilities
$
933

 
$
504

 
$
20

 
$
1,457

___________
(1)
As of June 30, 2012 and December 31, 2011, we had cash equivalents of $574 million and $1,249 million included in cash and cash equivalents and $149 million and $166 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation 
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Balance, beginning of period
$
17

 
$
12

 
$
17

 
$
30

Realized and unrealized gains (losses):
 
 
 
 
 
 
 
Included in net loss:
 
 
 
 
 
 
 
Included in operating revenues(1)
(24
)
 
10

 
(17
)
 
6

Included in fuel and purchased energy expense(2)
2

 
1

 
—

 
—

Included in OCI
—

 
4

 
4

 
5

Purchases, issuances and settlements:
 
 
 
 
 
 
 
Purchases
1

 
1

 
1

 
1

Issuances
(1
)
 
—

 
(1
)
 
—

Settlements
(5
)
 
(7
)
 
(11
)
 
(21
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
Transfers into level 3(4)
—

 
—

 
—

 
—

Transfers out of level 3(5)
—

 
—

 
(3
)
 
—

Balance, end of period
$
(10
)
 
$
21

 
$
(10
)
 
$
21

Change in unrealized gains (losses) relating to instruments still held at end of period
$
(22
)
 
$
11

 
$
(17
)
 
$
7

___________
(1)
For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(3)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into/out of level 1 during the three and six months ended June 30, 2012 and 2011.
(4)
There were no transfers out of level 2 into level 3 for the three and six months ended June 30, 2012 and 2011.
(5)
We had $3 million of transfers out of level 3 into level 2 for the six months ended June 30, 2012. There were no transfers out of level 3 for the three months ended June 30, 2012 and for the three and six months ended June 30, 2011.
Derivative Instruments (Tables)
Schedule of Notional Amounts of Outstanding Derivative Positions 
As of June 30, 2012 and December 31, 2011, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
June 30, 2012
 
December 31, 2011
Power (MWh)
 
(21
)
 
(21
)
Natural gas (MMBtu)
 
(68
)
 
(200
)
Interest rate swaps(1)
 
$
1,592

 
$
5,639

____________
(1)
Approximately $4.1 billion at December 31, 2011 was related to hedges of our First Lien Credit Facility's variable rate debt that was converted to fixed rate debt. On March 26, 2012, we terminated the interest rate swaps formerly hedging our First Lien Credit Facility.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value 
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
  
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
—

 
$
1,049

 
$
1,049

Long-term derivative assets
6

 
152

 
158

Total derivative assets
$
6

 
$
1,201

 
$
1,207

 
 
 
 
 
 
Current derivative liabilities
$
31

 
$
1,212

 
$
1,243

Long-term derivative liabilities
166

 
110

 
276

Total derivative liabilities
$
197

 
$
1,322

 
$
1,519

Net derivative assets (liabilities)
$
(191
)
 
$
(121
)
 
$
(312
)
 
December 31, 2011
 
Interest Rate
Swaps
 
Commodity
Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
—

 
$
1,051

 
$
1,051

Long-term derivative assets
10

 
103

 
113

Total derivative assets
$
10

 
$
1,154

 
$
1,164

 
 
 
 
 
 
Current derivative liabilities
$
166

 
$
978

 
$
1,144

Long-term derivative liabilities
154

 
125

 
279

Total derivative liabilities
$
320

 
$
1,103

 
$
1,423

Net derivative assets (liabilities)
$
(310
)
 
$
51

 
$
(259
)
Derivative Instrument by Accounting Designation 
 
June 30, 2012
 
December 31, 2011
 
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(1):
 
 
 
 
 
 
 
Interest rate swaps
$
6

 
$
176

 
$
10

 
$
149

Commodity instruments
28

 
4

 
51

 
18

Total derivatives designated as cash flow hedging instruments
$
34

 
$
180

 
$
61

 
$
167

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Interest rate swaps
$
—

 
$
21

 
$
—

 
$
171

Commodity instruments
1,173

 
1,318

 
1,103

 
1,085

Total derivatives not designated as hedging instruments
$
1,173

 
$
1,339

 
$
1,103

 
$
1,256

Total derivatives
$
1,207

 
$
1,519

 
$
1,164

 
$
1,423

____________
(1)
Includes accumulated fair value of derivative instruments as of the date hedge accounting was discontinued, net of amortized fair value for settlement periods which have transpired.
Realized Unrealized Gain Loss by Instrument 
The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized gain (loss)
 
 
 
 
 
 
 
Interest rate swaps
$
—

 
$
(60
)
 
$
(157
)
 
$
(106
)
Commodity derivative instruments
94

 
42

 
212

 
52

Total realized gain (loss)
$
94

 
$
(18
)
 
$
55

 
$
(54
)
 
 
 
 
 
 
 
 
Unrealized gain (loss)(1)
 
 
 
 
 
 
 
Interest rate swaps
$
3

 
$
24

 
$
149

 
$
(38
)
Commodity derivative instruments
(346
)
 
26

 
(268
)
 
(39
)
Total unrealized gain (loss)
$
(343
)
 
$
50

 
$
(119
)
 
$
(77
)
Total mark-to-market activity, net
$
(249
)
 
$
32

 
$
(64
)
 
$
(131
)
___________
(1)
In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Realized and unrealized gain (loss)
 
 
 
 
 
 
 
Power contracts included in operating revenues
$
(272
)
 
$
48

 
$
(180
)
 
$
(9
)
Natural gas contracts included in fuel and purchased energy expense
20

 
20

 
124

 
22

Interest rate swaps included in interest expense
3

 
1

 
6

 
2

Loss on interest rate derivatives
—

 
(37
)
 
(14
)
 
(146
)
Total mark-to-market activity, net
$
(249
)
 
$
32

 
$
(64
)
 
$
(131
)
Derivatives Designated as Hedges 
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):

 
Three Months Ended June 30,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(1)
 
Gain (Loss) Reclassified from
AOCI into Income  (Ineffective
Portion)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Interest rate swaps
$
(35
)
 
$
(9
)
 
$
(8
)
(2) 
$
(22
)
(2) 
$
—

 
$
(1
)
Commodity derivative instruments
(13
)
 
(39
)
 
12

(3) 
53

(3) 
—

 
1

Total
$
(48
)
 
$
(48
)
 
$
4

 
$
31

  
$
—

 
$
—


 
Six Months Ended June 30,
 
Gain (Loss) Recognized  in
OCI (Effective Portion)
 
Gain (Loss) Reclassified  from
AOCI into Income (Effective
Portion)(1)
 
Gain (Loss) Reclassified from
AOCI into Income  (Ineffective
Portion)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Interest rate swaps
$
(34
)
 
$
94

 
$
(15
)
(4) 
$
(123
)
(4) 
$
—

 
$
(1
)
Commodity derivative instruments
(14
)
 
(36
)
 
29

(3) 
79

(3) 
2

 
1

Total
$
(48
)
 
$
58

 
$
14

 
$
(44
)
  
$
2

 
$
—

____________
(1)
Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $216 million and $172 million at June 30, 2012 and December 31, 2011, respectively.
(2)
Reclassification of losses from OCI to earnings consisted of $8 million and $7 million from the reclassification of interest rate contracts due to settlement for the three months ended June 30, 2012 and 2011, respectively, and $15 million in losses from terminated interest rate contracts due to repayment of project debt in June 2011 for the three months ended June 30, 2011.
(3)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statement of Operations.
(4)
Reclassification of losses from OCI to earnings consisted of $15 million and $17 million from the reclassification of interest rate contracts due to settlement for the six months ended June 30, 2012 and 2011, respectively, $15 million in losses from terminated interest rate contracts due to repayment of project debt in June 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans for the six months ended June 30, 2011.
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, 2012 and December 31, 2011 (in millions):
 
June 30, 2012
 
December 31, 2011
Margin deposits(1)
$
262

 
$
140

Natural gas and power prepayments
37

 
42

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
299

 
$
182

 
 
 
 
Letters of credit issued
$
561

 
$
581

First priority liens under power and natural gas agreements
1

 
1

First priority liens under interest rate swap agreements
203

 
318

Total letters of credit and first priority liens with our counterparties
$
765

 
$
900

 
 
 
 
Margin deposits held by us posted by our counterparties(1)(3)
$
45

 
$
34

Letters of credit posted with us by our counterparties
1

 
—

Total margin deposits and letters of credit posted with us by our counterparties
$
46

 
$
34

___________
(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.
(2)
At June 30, 2012 and December 31, 2011, $275 million and $162 million, respectively, were included in margin deposits and other prepaid expense and $24 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
Income Taxes Income Taxes (Tables)
Schedule of Components of Income Tax Expense (Benefit) 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Income tax expense (benefit)
$
(52
)
 
$
18

 
$
(58
)
 
$
(65
)
(1 
) 
Imputed tax rate
14
%
 
(35
)%
 
15
%
 
15
%
 
_________
(1)
Includes a tax benefit of approximately $76 million related to the election to consolidate our CCFC and Calpine groups for federal income tax reporting purposes for the six months ended June 30, 2011.
Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation 
The following table details the effects of our intraperiod tax allocations for the three and six months ended June 30, 2012 and 2011 (in millions).
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Intraperiod tax allocation expense (benefit) included in continuing operations
$
2

 
$
18

 
$
4

 
$
(16
)
Intraperiod tax allocation expense (benefit) included in OCI
$
(2
)
 
$
(18
)
 
$
(4
)
 
$
16

Earnings (Loss) per Share (Tables)
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share
We excluded the following items from diluted loss per common share for the three and six months ended June 30, 2012 and 2011, because they were anti-dilutive (shares in thousands):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Share-based awards
13,920

 
15,309

 
15,236

 
15,131

Stock-Based Compensation (Tables)
Schedule of Non-Qualified Stock Option Activity 
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2012, is as follows:
 
Number of
Shares
 
Weighted Average
Exercise Price
 
Weighted
Average
Remaining
Term
(in years)
 
Aggregate
Intrinsic Value
(in millions)
Outstanding — December 31, 2011
17,665,902

 
$
17.32

 
4.8
 
$
26

Granted
888,407

 
$
15.33

 
 
 
 
Exercised
159,700

 
$
16.07

 
 
 
 
Forfeited
43,447

 
$
11.76

 
 
 
 
Expired
74,300

 
$
17.74

 
 
 
 
Outstanding — June 30, 2012
18,276,862

 
$
17.24

 
4.5
 
$
28

Exercisable — June 30, 2012
8,835,451

 
$
18.69

 
4.3
 
$
7

Vested and expected to vest – June 30, 2012
17,866,052

 
$
17.31

 
4.4
 
$
27

Schedule of Assumptions Used to Estimate Fair Value for Options 
Certain assumptions were used in order to estimate fair value for options as noted in the following table.
 
2012
 
2011
 
Expected term (in years)(1)
6.5

 
6.5

 
Risk-free interest rate(2)
1.6

%
2.7 – 3.2

%
Expected volatility(3)
30.0 – 30.5

%
31.2 – 31.7

%
Dividend yield(4)
—

 
—

 
Weighted average grant-date fair value (per option)
$
5.18

 
$
5.48

 
___________
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3)
Volatility calculated using the implied volatility of our exchange traded stock options.
(4)
We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future.
Schedule of Restricted Stock and Restricted Stock Unit Activity 
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2012, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2011
3,510,358

 
$
12.10

Granted
1,554,311

 
$
15.38

Forfeited
135,638

 
$
13.33

Vested
1,042,095

 
$
10.08

Nonvested — June 30, 2012
3,886,936

 
$
13.89

Segment and Significant Customer Information (Tables)
Schedule of Financial Data for Segments
The tables below show our financial data for our segments for the periods indicated (in millions).
 
Three Months Ended June 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
258

 
$
188

 
$
269

 
$
164

 
$
—

 
$
879

Intersegment revenues
1

 
41

 
2

 
(6
)
 
(38
)
 
—

Total operating revenues
$
259

 
$
229

 
$
271

 
$
158

 
$
(38
)
 
$
879

Commodity Margin(1)
$
210

 
$
145

 
$
181

 
$
73

 
$
—

 
$
609

Add: Mark-to-market commodity activity, net and other(2)(3)
(76
)
 
(217
)
 
(3
)
 
(42
)
 
(6
)
 
(344
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
112

 
72

 
58

 
36

 
(7
)
 
271

Depreciation and amortization expense
49

 
34

 
34

 
22

 
(1
)
 
138

Sales, general and other administrative expense
6

 
13

 
8

 
7

 
1

 
35

Other operating expenses(4)
9

 
1

 
6

 
2

 
1

 
19

(Income) from unconsolidated investments in power plants
—

 
—

 
(5
)
 
—

 
—

 
(5
)
Income (loss) from operations
(42
)
 
(192
)
 
77

 
(36
)
 
—

 
(193
)
Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
182

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
6

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(381
)

 
Three Months Ended June 30, 2011
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
466

 
$
646

 
$
324

 
$
197

 
$
—

 
$
1,633

Intersegment revenues
1

 
5

 
5

 
40

 
(51
)
 
—

Total operating revenues
$
467

 
$
651

 
$
329

 
$
237

 
$
(51
)
 
$
1,633

Commodity Margin(1)
$
236

 
$
128

 
$
184

 
$
59

 
$
—

 
$
607

Add: Mark-to-market commodity activity, net and other(2)(3)
11

 
27

 
(5
)
 
—

 
(9
)
 
24

Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
116

 
63

 
47

 
41

 
(6
)
 
261

Depreciation and amortization expense
42

 
35

 
33

 
22

 
(1
)
 
131

Sales, general and other administrative expense
8

 
13

 
6

 
6

 
1

 
34

Other operating expenses(4)
11

 
3

 
9

 
2

 
(5
)
 
20

Loss from unconsolidated investments in power plants
—

 
—

 
2

 
—

 
—

 
2

Income (loss) from operations
70

 
41

 
82

 
(12
)
 
2

 
183

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
190

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
37

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
8

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(52
)

 
Six Months Ended June 30, 2012
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
674

 
$
544

 
$
567

 
$
330

 
$
—

 
$
2,115

Intersegment revenues
5

 
61

 
5

 
16

 
(87
)
 
—

Total operating revenues
$
679

 
$
605

 
$
572

 
$
346

 
$
(87
)
 
$
2,115

Commodity Margin(1)
$
418

 
$
254

 
$
325

 
$
129

 
$
—

 
$
1,126

Add: Mark-to-market commodity activity, net and other(2)(5)
(40
)
 
(183
)
 
9

 
(32
)
 
(14
)
 
(260
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
193

 
140

 
103

 
69

 
(13
)
 
492

Depreciation and amortization expense
99

 
69

 
67

 
45

 
(2
)
 
278

Sales, general and other administrative expense
14

 
24

 
14

 
15

 
1

 
68

Other operating expenses(4)
20

 
3

 
15

 
3

 
(1
)
 
40

(Income) from unconsolidated investments in power plants
—

 
—

 
(14
)
 
—

 
—

 
(14
)
Income (loss) from operations
52


(165
)

149


(35
)

1

 
2

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
364

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
14

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
20

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(396
)

 
Six Months Ended June 30, 2011
 
West
 
Texas
 
North
 
Southeast
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,065

 
$
1,096

 
$
595

 
$
376

 
$
—

 
$
3,132

Intersegment revenues
4

 
10

 
13

 
85

 
(112
)
 
—

Total operating revenues
$
1,069

 
$
1,106

 
$
608

 
$
461

 
$
(112
)
 
$
3,132

Commodity Margin(1)
$
469

 
$
195

 
$
319

 
$
113

 
$
—

 
$
1,096

Add: Mark-to-market commodity activity, net and other(2)(5)
16

 
(33
)
 
(1
)
 
(4
)
 
(15
)
 
(37
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Plant operating expense
203

 
143

 
92

 
74

 
(13
)
 
499

Depreciation and amortization expense
88

 
65

 
66

 
45

 
(2
)
 
262

Sales, general and other administrative expense
19

 
23

 
12

 
11

 
1

 
66

Other operating expenses(4)
19

 
3

 
16

 
3

 
(3
)
 
38

(Income) from unconsolidated investments in power plants
—

 
—

 
(7
)
 
—

 
—

 
(7
)
Income (loss) from operations
156


(72
)

139


(24
)

2

 
201

Interest expense, net of interest income
 
 
 
 
 
 
 
 
 
 
378

Loss on interest rate derivatives
 
 
 
 
 
 
 
 
 
 
146

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
108

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(431
)
_________
(1)
Our North segment includes Commodity Margin related to Riverside Energy Center, LLC of $24 million and $22 million for three months ended June 30, 2012 and 2011, respectively, and $32 million and $31 million for the six months ended June 30, 2012 and 2011, respectively.
(2)
Mark-to-market commodity activity represents the change in the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations. The increase in unrealized mark-to-market losses for the three and six months ended June 30, 2012, was primarily driven by the impact of a near term increase in forward power prices and corresponding Market Heat Rate expansion in the ERCOT region during the last several days of June 2012.
(3)
Includes $(1) million and $4 million of lease levelization and $3 million and $1 million of amortization expense for the three months ended June 30, 2012 and 2011, respectively.
(4)
Excludes $2 million of RGGI compliance and other environmental costs for both the three months ended June 30, 2012 and 2011, and $5 million and $4 million for the six months ended June 30, 2012 and 2011, respectively, which are components of Commodity Margin.
(5)
Includes $(9) million and $4 million of lease levelization and $7 million and $1 million of amortization expense for the six months ended June 30, 2012 and 2011, respectively.
Summary of Significant Accounting Policies (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Dec. 31, 2011
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
 
 
Non-current
$ 51 
 
$ 51 
 
$ 55 
Current
124 
 
124 
 
139 
Total
175 
 
175 
 
194 
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]
 
 
 
 
 
Cash and cash equivalents subject to project finance facilities and lease agreements
178 
 
178 
 
306 
Held-to-maturity Securities, Restricted
25 
 
25 
 
25 
Interest Costs Capitalized
9 
4 
17 
11 
 
Inventory
262 
 
262 
 
294 
Treasury Stock, Value, Acquired, Cost Method
 
 
290 
 
 
Adjustments Related to Tax Withholding for Share-based Compensation
 
 
5 
 
 
Debt Service
 
 
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
 
 
Non-current
42 
 
42 
 
42 
Current
16 
 
16 
 
11 
Total
58 
 
58 
 
53 
Rent Reserve
 
 
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
 
 
Non-current
0 
 
0 
 
0 
Current
7 
 
7 
 
0 
Total
7 
 
7 
 
0 
Construction Major Maintenance
 
 
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
 
 
Non-current
2 
 
2 
 
10 
Current
47 
 
47 
 
33 
Total
49 
 
49 
 
43 
Security Project Insurance
 
 
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
 
 
Non-current
5 
 
5 
 
0 
Current
54 
 
54 
 
79 
Total
59 
 
59 
 
79 
Other
 
 
 
 
 
Restricted Cash and Cash Equivalents Items [Line Items]
 
 
 
 
 
Non-current
2 
 
2 
 
3 
Current
0 
 
0 
 
16 
Total
$ 2 
 
$ 2 
 
$ 19 
Summary of Significant Accounting Policies Contractual Future Minimum Lease Receipt Table (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Summary of Significant Accounting Policies [Abstract]
 
Operating Leases, Future Minimum Payments Receivable, Current
$ 285 
Operating Leases, Future Minimum Payments Receivable, in Two Years
527 
Operating Leases, Future Minimum Payments Receivable, in Three Years
465 
Operating Leases, Future Minimum Payments Receivable, in Four Years
481 
Operating Leases, Future Minimum Payments Receivable, in Five Years
396 
Operating Leases, Future Minimum Payments Receivable, Thereafter
2,312 
Operating Leases, Future Minimum Payments Receivable
$ 4,466 
Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Property, Plant and Equipment [Line Items]
 
 
Buildings, machinery and equipment
$ 15,154 
$ 15,074 
Geothermal properties
1,199 
1,163 
Other
157 
156 
Property, Plant and Equipment, Gross
16,510 
16,393 
Less: Accumulated depreciation
4,405 
4,158 
Property, Plant and Equipment, Gross, Less Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment
12,105 
12,235 
Land
90 
91 
Construction in progress
914 
693 
Property, plant and equipment, net
$ 13,109 
$ 13,019 
Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 76 
$ 80 
Greenfield [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
69 
72 
Equity Method Investment, Ownership Percentage
50.00% 
 
Whitby [Member]
 
 
Schedule of Equity Method Investments [Line Items]
 
 
Equity Method Investments
$ 7 
$ 8 
Equity Method Investment, Ownership Percentage
50.00% 
 
Variable Interest Entities and Unconsolidated Investments (Income from Unconsolidated Investements 10-Q) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
(Income) loss from unconsolidated investments in power plants
$ (5)
$ 2 
$ (14)
$ (7)
Greenfield [Member]
 
 
 
 
(Income) loss from unconsolidated investments in power plants
(2)
4 
(8)
(1)
Whitby [Member]
 
 
 
 
(Income) loss from unconsolidated investments in power plants
$ (3)
$ (2)
$ (6)
$ (6)
Variable Interest Entities and Unconsolidated Investments (VIE Textuals) (Details)
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, 2012
USD ($)
MW
Jun. 30, 2011
USD ($)
Jun. 30, 2012
USD ($)
MW
Jun. 30, 2011
USD ($)
Dec. 31, 2011
USD ($)
MW
Jun. 30, 2012
Inland Empire Energy Center [Member]
MW
Jun. 30, 2012
Inland Empire Energy Center [Member]
Minimum [Member]
Jun. 30, 2012
Inland Empire Energy Center [Member]
Maximum [Member]
Jun. 30, 2012
Greenfield [Member]
USD ($)
Jun. 30, 2011
Greenfield [Member]
USD ($)
Jun. 30, 2012
Greenfield [Member]
USD ($)
Jun. 30, 2011
Greenfield [Member]
USD ($)
Jun. 30, 2012
Greenfield [Member]
CAD ($)
MW
Jun. 30, 2012
Whitby [Member]
USD ($)
MW
Jun. 30, 2011
Whitby [Member]
USD ($)
Jun. 30, 2012
Whitby [Member]
USD ($)
MW
Jun. 30, 2011
Whitby [Member]
USD ($)
Jun. 30, 2012
Riverside Energy Center [Member]
USD ($)
MW
Variable Interest Entity [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power generation capacity
10,500 
 
10,500 
 
11,391 
775 
 
 
 
 
 
 
1,038 
50 
 
50 
 
603 
Proceeds from Sale of Productive Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 392 
Assets
16,887 
 
16,887 
 
17,371 
 
 
 
 
 
 
 
 
 
 
 
 
422 
Liabilities
13,184 
 
13,184 
 
13,007 
 
 
 
 
 
 
 
 
 
 
 
 
5 
Variable Interest Entity, Financial or Other Support, Amount
0 
0 
0 
72 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity Method Investment, Ownership Percentage
 
 
 
 
 
 
 
 
 
 
 
 
50.00% 
50.00% 
 
50.00% 
 
 
Equity Method Investment, Summarized Financial Information, Debt
448 
 
448 
 
462 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt
224 
 
224 
 
231 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity Method Investment, Summarized Financial Information, Term Loan Period
 
 
 
 
 
 
 
 
 
 
 
 
18 
 
 
 
 
 
Equity Method Investment, Summarized Financial Information, Term Loan
 
 
 
 
 
 
 
 
 
 
 
 
648 
 
 
 
 
 
Project financing interest rate spread - Canadian LIBOR
 
 
 
 
 
 
 
 
 
 
 
 
1.125% 
 
 
 
 
 
Project financing interest rate spread - Canadian Prime Rate
 
 
 
 
 
 
 
 
 
 
 
 
0.125% 
 
 
 
 
 
Return on investment in unconsolidated subsidiaries
 
 
 
 
 
 
 
 
$ 9 
$ 2 
$ 9 
$ 2 
 
$ 7 
$ 4 
$ 7 
$ 4 
 
Call Option Exercise Period
 
 
 
 
 
 
2,017 
2,024 
 
 
 
 
 
 
 
 
 
 
Put Option Exercise Period
 
 
 
 
 
2,025 
 
 
 
 
 
 
 
 
 
 
 
 
Debt (Debt) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,591 
$ 10,425 
Debt, Current
103 
104 
Long-term Debt, Excluding Current Maturities
(10,488)
(10,321)
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
5,892 
5,892 
Notes Payable, Other Payables [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,865 
1,691 
Loans Payable [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,638 
1,646 
Secured Debt [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
975 
972 
Capital Lease Obligations [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 221 
$ 224 
Debt (First Lien Notes) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 10,591 
$ 10,425 
First Lien Notes 2017 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,200 
1,200 
First Lien Notes 2019 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
400 
400 
First Lien Notes 2020 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,092 
1,092 
First Lien Notes 2021 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
2,000 
2,000 
First Lien Notes 2023 [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
1,200 
1,200 
Corporate Debt Securities [Member]
 
 
Debt Instrument [Line Items]
 
 
Long-term Debt
$ 5,892 
$ 5,892 
Debt (Letter of Credit) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 771 
$ 763 
Corporate Revolving Facility [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
385 
440 
CDH [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
256 
193 
Various Project Financing Facilities [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Letters of Credit Outstanding, Amount
$ 130 
$ 130 
Debt (Fair Value of Debt) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt
$ 10,591 
$ 10,425 
Long Term Debt, Fair Value Excluding Capital Leases
10,722 
10,371 
Debt Excluding Capital Leases
10,210 
10,014 
Corporate Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt, Fair Value
6,340 
6,219 
Long-term Debt
5,892 
5,892 
Notes Payable and Other Payables excluding Leases [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt, Fair Value
1,667 1
1,467 1
Long-term Debt
1,705 1
1,504 1
Loans Payable [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt, Fair Value
1,630 
1,615 
Long-term Debt
1,638 
1,646 
Secured Debt [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt, Fair Value
1,085 
1,070 
Long-term Debt
$ 975 
$ 972 
Debt (Debt Textuals) (Details) (USD $)
6 Months Ended
Jun. 30, 2012
MW
Dec. 31, 2011
MW
Debt Instrument [Line Items]
 
 
Term loan interest rate spread option Federal Funds effective rate
0.50% 
 
Term loan interest rate spread option Prime Rate
2.25% 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum
3.25% 
 
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum
1.25% 
 
Percentage of principal amount of Term Loan to be paid quarterly
0.25% 
 
Percentage of Term Loan amounts held by lenders
50.00% 
 
Power generation capacity
10,500 
11,391 
Letters of credit issued
$ 561,000,000 
$ 581,000,000 
Upsize Facility Total
300,000,000 
 
Percentage added to Federal Funds Effective Rate to arrive at base rate
0.50% 
 
Repayment time for drawings under letters of credit
2 
 
Excess amount of asset sales requiring mandatory prepayments
3,000,000,000 
 
Minimum [Member]
 
 
Debt Instrument [Line Items]
 
 
Applicable margin range percentage above base rate
2.00% 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
3.00% 
 
Unused commitment fee range percentage
0.50% 
 
Maximum [Member]
 
 
Debt Instrument [Line Items]
 
 
Applicable margin range percentage above base rate
2.25% 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
3.25% 
 
Unused commitment fee range percentage
0.75% 
 
Russell City Project [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Face Amount
845,000,000 
 
Power generation capacity
619 
 
Construction Loan Facility
700,000,000 
 
Project Letter of Credit Facility
77,000,000 
 
Term Loan Period
10 
 
Debt Service Letter of Credit Facility
68,000,000 
 
Amount Drawn Under Construction Loan
414,000,000 
 
Letters of credit issued
61,000,000 
 
Noncontrolling Interest, Ownership Percentage by Parent
75.00% 
 
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners
25.00% 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
2.25% 
 
Los Esteros Project [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt Instrument, Face Amount
373,000,000 
 
Power generation capacity
188 
 
Power generation capacity after upgrade
309 
 
Construction Loan Facility
305,000,000 
 
Project Letter of Credit Facility
38,000,000 
 
Term Loan Period
10 
 
Debt Service Letter of Credit Facility
30,000,000 
 
Amount Drawn Under Construction Loan
139,000,000 
 
Letters of credit issued
$ 30,000,000 
 
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates
2.25% 
 
One Month [Member]
 
 
Debt Instrument [Line Items]
 
 
Interest periods for LIBOR rate borrowings
1 
 
Two Months [Member]
 
 
Debt Instrument [Line Items]
 
 
Interest periods for LIBOR rate borrowings
2 
 
Three Months [Member]
 
 
Debt Instrument [Line Items]
 
 
Interest periods for LIBOR rate borrowings
3 
 
Six Months [Member]
 
 
Debt Instrument [Line Items]
 
 
Interest periods for LIBOR rate borrowings
6 
 
Nine Months [Member]
 
 
Debt Instrument [Line Items]
 
 
Interest periods for LIBOR rate borrowings
9 
 
Twelve Months [Member]
 
 
Debt Instrument [Line Items]
 
 
Interest periods for LIBOR rate borrowings
12 
 
Assets and Liabilities with Recurring Fair Value Measurements (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
$ 723 1
$ 1,415 1
Margin deposits
262 2
140 2
Commodity futures contracts
923 
1,043 
Commodity forward contracts
278 3
111 3
Interest rate swaps
6 
10 
Total assets
2,192 
2,719 
Margin deposits held by us posted by our counterparties
45 2 4
34 2 4
Commodity futures contracts
745 
899 
Commodity forward contracts
577 3
204 3
Interest rate swaps
197 
320 
Liabilities, Fair Value Disclosure
1,564 
1,457 
Fair Value, Inputs, Level 1 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
723 1
1,415 1
Margin deposits
262 
140 
Commodity futures contracts
923 
1,043 
Commodity forward contracts
0 3
0 3
Interest rate swaps
0 
0 
Total assets
1,908 
2,598 
Margin deposits held by us posted by our counterparties
45 
34 
Commodity futures contracts
745 
899 
Commodity forward contracts
0 3
0 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
790 
933 
Fair Value, Inputs, Level 2 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
0 1
0 1
Margin deposits
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
252 3
74 3
Interest rate swaps
6 
10 
Total assets
258 
84 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
541 3
184 3
Interest rate swaps
197 
320 
Liabilities, Fair Value Disclosure
738 
504 
Fair Value, Inputs, Level 3 [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
0 1
0 1
Margin deposits
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
26 3
37 3
Interest rate swaps
0 
0 
Total assets
26 
37 
Margin deposits held by us posted by our counterparties
0 
0 
Commodity futures contracts
0 
0 
Commodity forward contracts
36 3
20 3
Interest rate swaps
0 
0 
Liabilities, Fair Value Disclosure
$ 36 
$ 20 
Physical Power [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
(8,000,000.0000)
 
Minimum [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
19.3000 
 
Maximum [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Fair Value Inputs Quantitative Information Power
160.7500 
 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Dec. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Balance, beginning of period
$ 17 
$ 12 
$ 17 
$ 30 
 
Included in net income:
 
 
 
 
 
Included in operating revenues
(24)1
10 1
(17)1
6 1
 
Included in fuel and purchased energy expense
2 2
1 2
0 2
0 2
 
Included in OCI
0 
4 
4 
5 
 
Purchases, issuances and settlements:
 
 
 
 
 
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount
0 
0 
0 
0 
 
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount
0 
0 
0 
0 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases
1 
1 
1 
1 
 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issues
(1)
0 
(1)
0 
 
Settlements
(5)
(7)
(11)
(21)
 
Transfers into level 3
0 3
0 3
0 3
0 3
 
Transfers out of level 3
0 4
0 4
(3)4
0 4
 
Balance, end of period
(10)
21 
(10)
21 
 
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Change in Unrealized Gain (Loss) Held At Period End
(22)
11 
(17)
7 
 
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
 
 
 
 
 
Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure
574 
 
574 
 
1,249 
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure
$ 149 
 
$ 149 
 
$ 166 
Derivative Instruments (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2012
MMBTU
MW
Jun. 30, 2011
Jun. 30, 2012
MMBTU
MW
Jun. 30, 2011
Dec. 31, 2011
MMBTU
MW
Price Risk Derivatives [Abstract]
 
 
 
 
 
Power (MWh)
(21)
 
(21)
 
(21)
Natural gas (MMBtu)
(68)
 
(68)
 
(200)
Interest rate swaps
$ 1,592 1
 
$ 1,592 1
 
$ 5,639 1
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
 
Early Repayment of Senior Debt
 
 
 
 
1,200 
Unrealized losses associated with interest rate swap breakage costs
8 
7 
15 
17 
 
Notional Amount Interest Rate Derivative Underlying Debt Repaid During Period
 
 
 
 
1,000 
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net
 
 
 
$ 91 
$ 91 
Derivative Instruments (Details 2) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Derivatives, Fair Value [Line Items]
 
 
Derivative Assets, Current
$ 1,049 
$ 1,051 
Derivative Assets, Noncurrent
158 
113 
Total derivative assets
1,207 
1,164 
Current derivative liabilities
1,243 
1,144 
Derivative Liabilities, Noncurrent
276 
279 
Total derivative liabilities
(1,519)
(1,423)
Net derivative assets (liabilities)
(312)
(259)
Fair Value of Derivative Assets
1,207 
1,164 
Fair Value of Derivative Liabilities
1,519 
1,423 
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
34 1
61 1
Fair Value of Derivative Liabilities
180 1
167 1
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
1,173 
1,103 
Fair Value of Derivative Liabilities
1,339 
1,256 
Interest Rate Swap [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
0 
0 
Long-term derivative assets
6 
10 
Total derivative assets
6 
10 
Current derivative liabilities
31 
166 
Derivative Liabilities, Noncurrent
166 
154 
Total derivative liabilities
(197)
(320)
Net derivative assets (liabilities)
(191)
(310)
Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
6 1
10 1
Fair Value of Derivative Liabilities
176 1
149 1
Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
0 
0 
Fair Value of Derivative Liabilities
21 
171 
Commodity Option [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Current derivative assets
1,049 
1,051 
Long-term derivative assets
152 
103 
Total derivative assets
1,201 
1,154 
Current derivative liabilities
1,212 
978 
Derivative Liabilities, Noncurrent
110 
125 
Total derivative liabilities
(1,322)
(1,103)
Net derivative assets (liabilities)
(121)
51 
Commodity Option [Member] |
Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
28 1
51 1
Fair Value of Derivative Liabilities
4 1
18 1
Commodity Option [Member] |
Not Designated as Hedging Instrument [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair Value of Derivative Assets
1,173 
1,103 
Fair Value of Derivative Liabilities
$ 1,318 
$ 1,085 
Derivative Instruments (Details 3) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Power contracts included in operating revenues
$ (272)
$ 48 
$ (180)
$ (9)
Natural gas contracts included in fuel and purchased energy expense
20 
20 
124 
22 
Interest rate swaps included in interest expense
3 
1 
6 
2 
Gain (Loss) on interest rate derivatives, net
0 
37 
14 
146 
Gain (Loss) on Derivative Instruments, Net, Pretax
(249)1
32 1
(64)1
(131)1
Gain (Loss) on Sale of Derivatives
94 
(18)
55 
(54)
Unrealized gain (loss)
(343)1
50 1
(119)1
(77)1
Interest Rate Swap [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Gain (Loss) on Sale of Derivatives
0 
(60)
(157)
(106)
Unrealized gain (loss)
3 1
24 1
149 1
(38)1
Commodity Option [Member]
 
 
 
 
Summary of Derivative Instruments by Risk Exposure [Abstract]
 
 
 
 
Gain (Loss) on Sale of Derivatives
94 
42 
212 
52 
Unrealized gain (loss)
$ (346)1
$ 26 1
$ (268)1
$ (39)1
Derivative Instruments (Details 4) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
$ (48)
$ (48)
$ (48)
$ 58 
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
4 1
31 1
14 1
(44)1
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
0 
0 
2 
0 
Interest Rate Swap [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
(35)
(9)
(34)
94 
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
(8)1 2
(22)1 2
(15)1 3
(123)1 3
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
0 
(1)
0 
(1)
Commodity Option [Member]
 
 
 
 
Derivative Instruments, Gain (Loss) [Line Items]
 
 
 
 
Gains (Loss) Recognized in OCI (Effective Portion)
(13)
(39)
(14)
(36)
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)
12 1 4
53 1 4
29 1 4
79 1 4
Gain (Loss) Reclassified from AOCI into Income (IneffectivePortion)
$ 0 
$ 1 
$ 2 
$ 1 
Derivative Instruments (Textuals) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2012
Mar. 31, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Dec. 31, 2011
Derivative Instruments (Textuals) [Abstract]
 
 
 
 
 
 
Maximum length of time hedging using interest rate derivative instruments
 
 
 
11 years 
 
 
Derivative, Net Liability Position, Aggregate Fair Value
$ 339 
 
 
$ 339 
 
 
Collateral Already Posted, Aggregate Fair Value
244 
 
 
244 
 
 
Additional Collateral, Aggregate Fair Value
5 
 
 
5 
 
 
Early Repayment of Senior Debt
 
 
 
 
 
1,200 
Notional Amount Interest Rate Derivative Underlying Debt Repaid During Period
 
 
 
 
 
1,000 
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net
 
 
 
 
91 
91 
Unrealized losses associated with interest rate swap breakage costs
8 
 
7 
15 
17 
 
Cumulative cash flow hedge losses remaining in AOCI
 
 
 
216 
 
172 
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months
 
 
 
6 
 
 
Losses from interest rate contracts reclassified from OCI into earnings
 
 
15 
 
15 
 
Notional Amount Interest Rate Derivative Underlying Debt Repaid
 
 
 
 
 
4,100 
Interest Rate Derivative Liabilities, Fair Value on Settlement Date [Line Items]
 
 
 
 
 
 
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments
 
142 
 
 
 
 
Interest Rate Derivative Liabilities, Fair Value on Settlement Date
0 
 
(37)
(14)
(146)
 
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Unrealized
 
14 
 
 
 
 
Interest Rate Swap [Member]
 
 
 
 
 
 
Interest Rate Derivative Liabilities, Fair Value on Settlement Date [Line Items]
 
 
 
 
 
 
Interest Rate Derivative Liabilities, Fair Value on Settlement Date
 
$ 156 
 
 
 
 
Use of Collateral (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2012
Dec. 31, 2011
Use of Collateral [Abstract]
 
 
Margin deposits
$ 262 1
$ 140 1
Natural gas and power prepayments
37 
42 
Total margin deposits and natural gas and power prepayments with our counterparties
299 2
182 2
Letters of credit issued
561 
581 
First priority liens under power and natural gas agreements
1 
1 
First priority liens under interest rate swap agreements
203 
318 
Total letters of credit and first priority liens with our counterparties
765 
900 
Margin deposits held by us posted by our counterparties
45 1 3
34 1 3
Letters of credit posted with us by our counterparties
1 
0 
Total margin deposits and letters of credit posted with us by our counterparties
46 
34 
Use of Collateral (Textuals) [Abstract]
 
 
Margin And Prepayment Amounts Included In Other Assets
24 
20 
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses
$ 275 
$ 162 
Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)
3 Months Ended 6 Months Ended 12 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Dec. 31, 2011
Income Tax Disclosure [Abstract]
 
 
 
 
 
Operating Loss Carryforwards Available To Offset Future Income
 
 
 
 
$ 6,300,000,000 
One time tax benefit from consolidation
 
 
 
76,000,000 
 
Income tax expense (benefit)
(52,000,000)
18,000,000 
(58,000,000)
(65,000,000)1
 
Effective Income Tax Rate, Continuing Operations
14.00% 
(35.00%)
15.00% 
15.00% 
 
Income Tax Expense (Benefit), Intraperiod Tax Allocation
(2,000,000)
(18,000,000)
(4,000,000)
16,000,000 
 
NOLs expected to expire unutilized
 
 
 
 
640,000,000 
NOLs expired unutilized
 
 
50,000,000 
 
 
Percent Decline In Market Cap Required To Trigger Transfer Restrictions
35.00% 
 
35.00% 
 
 
Emergence Date Capitalization
8,600,000,000 
 
8,600,000,000 
 
 
Percent Change in Ownership Required To Trigger Transfer Restrictions
25.00% 
 
25.00% 
 
 
Holders with ownership that could be affected by transfer restrictions
5.00% 
 
5.00% 
 
 
Unrecognized Tax Benefits
84,000,000 
 
84,000,000 
 
 
Unrecognized Tax Benefits that Would Impact Effective Tax Rate
38,000,000 
 
38,000,000 
 
 
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward
46,000,000 
 
46,000,000 
 
 
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued
22,000,000 
 
22,000,000 
 
 
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions
 
 
9,000,000 
 
 
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound
0 
 
0 
 
 
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound
$ 23,000,000 
 
$ 23,000,000 
 
 
Earnings (Loss) per Share (Details)
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Earnings (Loss) per Share [Abstract]
 
 
 
 
Share-based awards
13,920,000 
15,309,000 
15,236,000 
15,131,000 
Shares Of New, Reorganized Common Stock
 
 
485,000,000 
 
Stock-Based Compensation Narrative (Details) (USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
Cash Received from Exercise of Stock Options
 
 
$ 3,000,000 
$ 0 
Fair Value of Restricted Stock That Vested
 
 
19,000,000 
7,000,000 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
 
Expected Term
 
 
6 years 6 months 1
6 years 6 months 1
Risk Free Interest Rate
 
 
1.60% 
 
Expected Dividend Rate
 
 
0.00% 2
0.00% 2
Weighted Average Grant Date Fair Value
 
 
$ 5.18 
$ 5.48 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
 
 
 
 
Nonvested Restricted Stock, Beginning balance
 
 
3,510,358 
 
Nonvested Restricted Stock, Beginning balance, Weighted Average Grant Date Fair Value
 
 
$ 12.10 
 
Grants in Period
 
 
1,554,311 
 
Grants in Period, Weighted Average Grant Date Fair Value
 
 
$ 15.38 
 
Forfeitures in Period
 
 
135,638 
 
Forfeitures in Period, Weighted Average Grant Date Fair Value
 
 
$ 13.33 
 
Vested in Period
 
 
1,042,095 
 
Vested in Period, Weighted Average Grant Date Fair Value
 
 
$ 10.08 
 
Nonvested Restricted Stock, Ending balance
3,886,936 
 
3,886,936 
 
Nonvested Restricted Stock, Ending balance, Weighted Average Grant Date Fair Value
$ 13.89 
 
$ 13.89 
 
Disclosure of Compensation Related Costs Share-based Payments (Textuals) [Abstract]
 
 
 
 
Vesting period for graded and cliff vesting options - minimum
 
 
1 year 
 
Vesting period for graded and cliff vesting options - maximum
 
 
5 years 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Minimum Range
 
 
5 years 
 
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Maximum Range
 
 
10 years 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Directors
567,000 
 
567,000 
 
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Employees
27,533,000 
 
27,533,000 
 
Vest Term of First Sub Grant
 
 
1 year 
 
Vest Term of the Second Sub-Grant
 
 
2 years 
 
Vest Term of the Third Sub-Grant
 
 
3 years 
 
Grants in Option Grants with Three Year Cliff Vesting
 
 
1 
 
Vesting term of option grants with three year cliff vesting
 
 
3 years 
 
Stock-based compensation expense
7,000,000 
7,000,000 
13,000,000 
12,000,000 
Minimum [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
 
Risk Free Interest Rate
 
 
 
2.70% 
Expected Volatility Rate
 
 
30.00% 
31.20% 
Maximum [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
 
Risk Free Interest Rate
 
 
 
3.20% 
Expected Volatility Rate
 
 
30.50% 
31.70% 
Stock Options [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
10,000,000 
 
10,000,000 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
 
 
1 year 1 month 6 days 
 
Restricted Stock [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
25,000,000 
 
25,000,000 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
 
 
1 year 8 months 12 days 
 
Restricted Stock Units (RSUs) [Member]
 
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
 
 
 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized
$ 0 
 
$ 0 
 
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition
 
 
10 months 24 days 
 
Stock-Based Compensation Schedule of Non-qualified Stock Option Activity (Details) (USD $)
In Millions, except Share data, unless otherwise specified
6 Months Ended 12 Months Ended
Jun. 30, 2012
Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
 
 
Options, Outstanding
18,276,862 
17,665,902 
Options, Outstanding, Weighted Average Exercise Price
$ 17.24 
$ 17.32 
Options, Outstanding, Weighted Average Remaining Contractual Term
4 years 6 months 
4 years 9 months 18 days 
Options, Outstanding, Intrinsic Value
$ 28 
$ 26 
Options, Grants in Period, Gross
888,407 
 
Options, Grants in Period, Weighted Average Exercise Price
$ 15.33 
 
Options, Exercises in Period
159,700 
 
Options, Exercises in Period, Weighted Average Exercise Price
$ 16.07 
 
Options, Forfeitures in Period
43,447 
 
Options, Forfeitures in Period, Weighted Average Exercise Price
$ 11.76 
 
Options, Expirations in Period
74,300 
 
Options, Expirations in Period, Weighted Average Exercise Price
$ 17.74 
 
Options, Exercisable
8,835,451 
 
Options, Exercisable, Weighted Average Exercise Price
$ 18.69 
 
Options, Exercisable, Weighted Average Remaining Contractual Term
4 years 3 months 18 days 
 
Options, Exercisable, Intrinsic Value
7 
 
Options, Vested and Expected to Vest, Outstanding
17,866,052 
 
Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price
$ 17.31 
 
Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term
4 years 4 months 24 days 
 
Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value
$ 27 
 
Segment and Significant Customer Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2012
Jun. 30, 2011
Jun. 30, 2012
Jun. 30, 2011
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenues from external customers
$ 879 
$ 1,633 
$ 2,115 
$ 3,132 
Intersegment revenues
0 
0 
0 
0 
Total operating revenues
879 
1,633 
2,115 
3,132 
Commodity Margin
609 
607 
1,126 
1,096 
Add: Mark-to-market commodity activity, net and other
(344)1 2
24 1 2
(260)1 3
(37)1 3
Plant operating expense
271 
261 
492 
499 
Depreciation and amortization expense
138 
131 
278 
262 
Sales, general and other administrative expense
35 
34 
68 
66 
Other operating expenses
19 4
20 4
40 4
38 4
(Income) loss from unconsolidated investments in power plants
(5)
2 
(14)
(7)
Operating Income (Loss)
(193)
183 
2 
201 
Interest expense, net of interest income
182 
190 
364 
378 
Loss on interest rate derivatives
0 
(37)
(14)
(146)
Debt Extinguishment Costs and Other (Income) Expense, Net
6 
8 
20 
108 
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest
(381)
(52)
(396)
(431)
Lease levelization
(1)
4 
(9)
4 
Contract amortization
3 
1 
7 
1 
RGGI compliance and other environmental costs
2 
2 
5 
4 
Commodity Margin Riverside Energy Center
24 
22 
32 
31 
West [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenues from external customers
258 
466 
674 
1,065 
Intersegment revenues
1 
1 
5 
4 
Total operating revenues
259 
467 
679 
1,069 
Commodity Margin
210 
236 
418 
469 
Add: Mark-to-market commodity activity, net and other
(76)1 2
11 1 2
(40)1 3
16 1 3
Plant operating expense
112 
116 
193 
203 
Depreciation and amortization expense
49 
42 
99 
88 
Sales, general and other administrative expense
6 
8 
14 
19 
Other operating expenses
9 4
11 4
20 4
19 4
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Operating Income (Loss)
(42)
70 
52 
156 
Texas [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenues from external customers
188 
646 
544 
1,096 
Intersegment revenues
41 
5 
61 
10 
Total operating revenues
229 
651 
605 
1,106 
Commodity Margin
145 
128 
254 
195 
Add: Mark-to-market commodity activity, net and other
(217)1 2
27 1 2
(183)1 3
(33)1 3
Plant operating expense
72 
63 
140 
143 
Depreciation and amortization expense
34 
35 
69 
65 
Sales, general and other administrative expense
13 
13 
24 
23 
Other operating expenses
1 4
3 4
3 4
3 4
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Operating Income (Loss)
(192)
41 
(165)
(72)
North [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenues from external customers
269 
324 
567 
595 
Intersegment revenues
2 
5 
5 
13 
Total operating revenues
271 
329 
572 
608 
Commodity Margin
181 5
184 5
325 5
319 5
Add: Mark-to-market commodity activity, net and other
(3)1 2
(5)1 2
9 1 3
(1)1 3
Plant operating expense
58 
47 
103 
92 
Depreciation and amortization expense
34 
33 
67 
66 
Sales, general and other administrative expense
8 
6 
14 
12 
Other operating expenses
6 4
9 4
15 4
16 4
(Income) loss from unconsolidated investments in power plants
(5)
2 
(14)
(7)
Operating Income (Loss)
77 
82 
149 
139 
Southeast [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenues from external customers
164 
197 
330 
376 
Intersegment revenues
(6)
40 
16 
85 
Total operating revenues
158 
237 
346 
461 
Commodity Margin
73 
59 
129 
113 
Add: Mark-to-market commodity activity, net and other
(42)1 2
0 1 2
(32)1 3
(4)1 3
Plant operating expense
36 
41 
69 
74 
Depreciation and amortization expense
22 
22 
45 
45 
Sales, general and other administrative expense
7 
6 
15 
11 
Other operating expenses
2 4
2 4
3 4
3 4
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Operating Income (Loss)
(36)
(12)
(35)
(24)
Consolidation and Elimination [Member]
 
 
 
 
Revenues from External Customers and Long-Lived Assets [Line Items]
 
 
 
 
Revenues from external customers
0 
0 
0 
0 
Intersegment revenues
(38)
(51)
(87)
(112)
Total operating revenues
(38)
(51)
(87)
(112)
Commodity Margin
0 
0 
0 
0 
Add: Mark-to-market commodity activity, net and other
(6)1 2
(9)1 2
(14)1 3
(15)1 3
Plant operating expense
(7)
(6)
(13)
(13)
Depreciation and amortization expense
(1)
(1)
(2)
(2)
Sales, general and other administrative expense
1 
1 
1 
1 
Other operating expenses
1 4
(5)4
(1)4
(3)4
(Income) loss from unconsolidated investments in power plants
0 
0 
0 
0 
Operating Income (Loss)
$ 0 
$ 2 
$ 1 
$ 2