CALPINE CORP, 10-Q/A filed on 8/11/2010
Amended Quarterly Report
Document and Company Information
Jul. 28, 2010
6 Months Ended
Jun. 30, 2010
Document and Company Information
 
 
Entity Registrant Name
 
Calpine Corp 
Entity Central Index Key
 
0000916457 
Entity Currrent Reporting Status
 
Yes 
Current Fiscal Year End Date
 
12/31 
Entity Filer Category
 
Large Accelerated Filer 
Entity Well Known Seasoned Issuer
 
Yes 
Document Fiscal Year Focus
 
2010 
Document Fiscal Period Focus
 
Q2 
Document Type
 
10-Q 
Document Period End Date
 
06/30/2010 
Amendment Flag
 
FALSE 
Entity Common Stock Shares Outstanding
444,586,271 
 
Consolidated Condensed Statements of Operations (Unaudited) (USD $)
In Millions, except Share data in Thousands and Per Share data
3 Months Ended
Jun. 30, 2010
6 Months Ended
Jun. 30, 2010
3 Months Ended
Jun. 30, 2009
6 Months Ended
Jun. 30, 2009
Consolidated Condensed Statements of Operations
 
 
 
 
Operating Revenues
$ 1,430 
$ 2,944 
$ 1,445 
$ 3,097 
Cost of revenue:
 
 
 
 
Fuel and purchased energy expense
904 
1,873 
922 
1,937 
Plant operating expense
213 
431 
206 
449 
Depreciation and amortization expense
132 
265 
108 
213 
Other cost of revenue
24 
45 
20 
43 
Total cost of revenue
1,273 
2,614 
1,256 
2,642 
Gross profit
157 
330 
189 
455 
Sales, general and other administrative expense
53 
78 
48 
93 
(Income) from unconsolidated investments in power plants
(6)
(13)
(23)
(40)
Other operating expense
Income from operations
108 
258 
159 
393 
Interest expense
216 
408 
203 
409 
Interest (income)
(4)
(6)
(4)
(10)
Debt extinguishment costs
33 
33 
Other (income) expense, net
(1)
Loss before reorganization items, income taxes and discontinued operations
(112)
(157)
(72)
(41)
Reorganization items
 
 
Loss before income taxes and discontinued operations
(112)
(157)
(75)
(47)
Income tax expense
17 
15 
24 
Loss before discontinued operations
(118)
(174)
(90)
(71)
Discontinued operations, net of tax expense
12 
11 
23 
Net loss
(114)
(162)
(79)
(48)
Net (income) loss attributable to the noncontrolling interest
(1)
 
Net loss attributable to Calpine
(115)
(162)
(78)
(46)
Basic and diluted loss per common share attributable to Calpine:
 
 
 
 
Weighted Average Number of Shares Outstanding, Basic and Diluted
486,057 
485,989 
485,675 
485,560 
Income (Loss) from Continuing Operations, Per Basic and Diluted Share
(0.25)
(0.35)
(0.18)
(0.14)
Income (Loss) from Discontinued Operations, Net of Tax, Per Basic and Diluted Share
0.01 
0.02 
0.02 
0.05 
Earnings Per Share, Basic and Diluted
$ (0.24)
$ (0.33)
$ (0.16)
$ (0.09)
Consolidated Condensed Balance Sheets (Unaudited) (USD $)
In Millions
Jun. 30, 2010
Dec. 31, 2009
ASSETS
 
 
Current assets:
 
 
Cash and cash equivalents
$ 971 
$ 989 
Accounts receivable, net of allowance
679 
750 
Margin deposits and other prepaid expense
331 
490 
Restricted cash, current
298 
508 
Derivative assets, current
1,240 
1,119 
Assets held for sale
548 
 
Inventory and other current assets
222 
243 
Total current assets
4,289 
4,099 
Property, plant and equipment, net
11,408 
11,583 
Restricted cash, net of current portion
47 
54 
Investments
89 
214 
Long-term derivative assets
223 
127 
Other long-term assets
593 
573 
Total assets
16,649 
16,650 
LIABILITIES & STOCKHOLDERS' EQUITY
 
 
Current liabilities:
 
 
Accounts payable
482 
578 
Accrued interest payable
59 
54 
Debt, current portion
699 
463 
Derivatives liabilities, current
1,244 
1,360 
Liabilities held for sale
13 
 
Other current liabilities
276 
294 
Total current liabilities
2,773 
2,749 
Debt, net of current portion
8,827 
8,996 
Deferred income taxes, net of current portion
112 
54 
Long-term derivative liabilities
382 
197 
Other long-term liabilities
216 
208 
Total liabilities
12,310 
12,204 
Commitments and contingencies (See Note 14)
 
 
Stockholders' equity:
 
 
Preferred stock, $.001 par value per share; 100,000,000 shares authorized; none issued and outstanding
 
 
Common stock, $.001 par value per share; 1,400,000,000 shares authorized; 445,034,189 and 443,325,827 shares issued, respectively, and 444,586,271 and 442,998,255 shares outstanding, respectively
Treasury stock, at cost, 447,918 and 327,572 shares, respectively
(5)
(3)
Additional paid-in capital
12,268 
12,256 
Accumulated deficit
(7,702)
(7,540)
Accumulated other comprehensive loss
(223)
(266)
Total Calpine stockholders' equity
4,339 
4,448 
Noncontrolling interest
 
(2)
Total stockholders' equity
4,339 
4,446 
Total liabilties and stockholders' equity
$ 16,649 
$ 16,650 
Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $)
In Millions
6 Months Ended
Jun. 30,
2010
2009
Consolidated Statement of Cash Flows
 
 
Cash flows from operating activities:
 
 
Net loss
$ (162)
$ (48)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
Depreciation and amortization expense (1)
298 1
268 1
Debt extinguishment cost
Deferred income taxes
(4)
26 
Loss on disposal of assets
20 
Unrealized mark-to-market activity, net
(62)
(23)
Income from unconsolidated investments in power plants
(13)
(40)
Stock-based compensation expense
12 
22 
Other operating activities
Change in operating assets and liabilities:
 
 
Accounts receivable
68 
29 
Derivative instruments, net
(81)
(257)
Other assets
171 
173 
Accounts payable and accrued expenses
(91)
(23)
Other liabilities
(191)
Net cash provided by (used in) operating activities
156 
(36)
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(97)
(97)
Cash acquired due to consolidation of OMEC
 
Contributions to unconsolidated investments
 
(8)
(Increase) decrease in restricted cash
224 
(31)
Other investing activities
(1)
Net cash provided by (used in) investing activities
138 
(137)
Cash flows from financing activities:
 
 
Repayments of project financing, notes payable and other
(277)
(969)
Borrowings from project financing, notes payable and other
 
1,027 
Issuance of First Lien Notes
400 
 
Repayments on First Lien Credit Facility
(430)
(30)
Financing costs
(15)
(29)
Refund of financing costs
10 
 
Other financing activities
 
(1)
Net cash used in financing activities
(312)
(2)
Net decrease in cash and cash equivalents
(18)
(175)
Cash and cash equivalents, beginning of period
989 
1,657 
Cash and cash equivalents, end of period
971 
1,482 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
362 
398 
Income taxes
Reorganization items included in operating activities, net
 
Supplemental disclosure of non-cash investing and financing activities:
 
 
Settlement of commodity contract with project financing
 
79 
Change in capital expenditures included in accounts payable
$ (7)
 
Balance Sheet Parentheticals (Unaudited) (USD $)
In Millions, except Share and Per Share data
Jun. 30, 2010
Dec. 31, 2009
Balance Sheet (Parentheticals)
 
 
Cash and cash equivalents at carrying value attributable to VIE
$ 207 
$ 242 
Accounts Receivable, allowance for doubtful accounts
14 
Restricted cash and cash equivalents at carrying value attributable to VIE
267 
322 
Assets held for sale current attributtable to VIE
548 
 
Property plant and equipment net attributable to VIE
5,208 
5,319 
Restricted cash and cash equivalents noncurrent attributable to VIE
40 
45 
Debt current attributable to VIE
575 
106 
Long term debt noncurrent attributable to VIE
2,816 
3,042 
Preferred Stock, par value
0.001 
0.001 
Preferred Stock, authorized shares
100,000,000 
100,000,000 
Preferred Stock, issued shares
Preferred Stock, outstanding shares
Common Stock, par value
0.001 
0.001 
Common Stock, authorized shares
1,400,000,000 
1,400,000,000 
Common Stock, issued shares
445,034,189 
443,325,827 
Common Stock, outstanding shares
444,586,271 
442,998,255 
Treasury Stock, shares
447,918 
327,572 
Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Summary of Significant Accounting Policies
1.  Basis of Presentation and Summary of Significant Accounting Policies

We are an independent wholesale power generation company engaged in the ownership and operation primarily of natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive power markets in the U.S., including CAISO and ERCOT, and the Conectiv Acquisition on July 1, 2010 (see Note 2), gives us significant presence in the PJM market. We sell wholesale power, steam, regulatory capacity, renewable energy credits and ancillary services to our customers, including industrial companies, retail power providers, utilities, municipalities, independent electric system operators, marketers and others. We engage in the purchase of natural gas 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 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, 2009, included in our 2009 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to seasonal fluctuations in our revenues, timing of major maintenance expense, volatility of commodity prices and unrealized gains and losses from derivative contracts.

Consolidation of OMEC — We were required by GAAP to adopt new accounting standards for VIEs which became effective January 1, 2010 and required us to perform an analysis to determine whether we should consolidate any of our previously unconsolidated VIEs or deconsolidate any of our previously consolidated VIEs. We completed our required analysis and determined that we are the primary beneficiary of OMEC. Accordingly, as required by GAAP, we consolidated OMEC effective January 1, 2010. The consolidation of OMEC on January 1, 2010 was accounted for using historical cost and resulted in the addition to our Consolidated Condensed Balance Sheet of approximately $8 million in cash and cash equivalents, $535 million in net property, plant and equipment, $26 million in other current and non-current assets, $375 million in project debt and $50 million in other current and non-current liabilities, and the removal of $144 million representing our investment balance in OMEC. Our Consolidated Condensed Financial Statements as of and for the three and six months ended June 30, 2010, include the consolidated balances of OMEC. We presented our investment in OMEC’s net assets, revenues and expenses under the equity method of accounting as of December 31, 2009, and for the three and six months ended June 30, 2009. We made no other changes to our group of subsidiaries that we consolidate as a result of the adoption of these new standards. See Note 4 for further discussion of accounting for our VIEs.

Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with 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.

Fair Value of Financial Instruments and Derivatives — The carrying values of cash equivalents (including amounts in restricted cash), accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments and Notes 7 and 8 for disclosures regarding the fair values of our derivative instruments.

Concentrations of Credit Risk — Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative assets. Certain of our cash and cash equivalents, as well as our restricted cash balances, exceed FDIC insured limits or are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe are credit-worthy financial institutions and 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. Additionally, we actively monitor the credit risk of our receivable and derivative counterparties. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity counterparties, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.

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, 2010, and December 31, 2009, we had cash and cash equivalents of $213 million and $264 million, respectively, that were subject to such project finance facilities and lease agreements. Cash and cash equivalent balances that can only be used to settle the obligations of our consolidated VIEs have been disclosed on the face of our Consolidated Condensed Balance Sheets as required under the new accounting standards for VIEs. See Note 4 for a further discussion of accounting for our VIEs.

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 are 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, 2010, and December 31, 2009 (in millions):

   
June 30, 2010
   
December 31, 2009
 
   
Current
   
Non-Current
   
Total
   
Current
   
Non-Current
   
Total
 
Debt service
  $ 56     $ 25     $ 81     $ 193     $ 25     $ 218  
Rent reserve
    17       5       22       34             34  
Construction/major maintenance
    91       15       106       87       22       109  
Security/project/insurance
    110             110       146             146  
Other
    24       2       26       48       7       55  
Total
  $ 298     $ 47     $ 345     $ 508     $ 54     $ 562  

Inventory — At June 30, 2010, and December 31, 2009, we had inventory of $188 million and $209 million, respectively. Inventory primarily consists of spare parts, stored natural gas, 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 are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Investments — We use the equity method of accounting to record our net interest in Greenfield LP, a 50% partnership interest and Whitby, a 50% equity interest where we exercise significant influence over operating and financial policies. As discussed above, we presented our investment in OMEC’s net assets, revenues and expenses under the equity method of accounting as of December 31, 2009, and for the three and six months ended June 30, 2009. Our share of net income (loss) is calculated according to our equity ownership or according to the terms of the applicable partnership agreement. See Note 4 for further discussion of our VIEs and unconsolidated investments.
 
New Accounting Standards and Disclosure Requirements

Consolidation of VIEs and Additional VIE Disclosures — Effective for interim and annual periods beginning after November 15, 2009, the Financial Accounting Standards Board amended the accounting standards for determining which enterprise is the primary beneficiary of a VIE, added additional VIE disclosure requirements and amended guidance for determining whether an entity is a VIE. The new standards generally replace the quantitative-based risks and rewards calculation for determining which enterprise, if any, is the primary beneficiary of a VIE to a more qualitative assessment with an approach focused on identifying which enterprise has the power to direct the activities of a VIE that most significantly impacts the VIE’s economic performance and also has the obligation to absorb losses or receive benefits from the VIE. We completed our analysis during the first quarter of 2010, and determined that the consolidation of OMEC was required. See Note 4 for further discussion of implementation of these new accounting standards.

The new standards and disclosure requirements also added:

 
A requirement to perform ongoing reassessments each reporting period of whether we are the primary beneficiary of our VIEs, which could require us to consolidate our VIEs that are currently not consolidated or deconsolidate our VIEs that are currently consolidated based upon our reassessments in future periods. No further changes to our determinations of whether we are the primary beneficiary of our VIEs were required during the second quarter of 2010.
 
Disclosure provisions to present separately on the face of the statement of financial position 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. Our Consolidated Condensed Balance Sheets include these required disclosures. The new standards also reduce required disclosures for consolidated VIEs without such restrictions if we are the equity holder and primary beneficiary.
 
An additional reconsideration event for determining whether an entity is a VIE if any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE’s economic performance.

Fair Value Measurements and Disclosures — In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures” to enhance disclosure requirements relating to different levels of assets and liabilities measured at fair value and to clarify certain existing disclosures. The update requires disclosure of significant transfers in and out of levels 1 and 2 and gross presentation of purchases, sales, issuances and settlements in the level 3 reconciliation of beginning and ending balances. The new disclosure requirements relating to level 3 activity are effective for interim and annual periods beginning after December 15, 2010, and all the other requirements are effective for interim and annual periods beginning after December 15, 2009. We adopted all of the disclosure requirements related to this update for the three and six months ended June 30, 2010 and 2009. Since this update only required additional disclosures, adoption of this standard did not have a material impact on our results of operations, cash flows or financial condition. See Note 7 for disclosure of our fair value measurements in accordance with these disclosure requirements.
Conectiv Acquisition and Planned Divestiture of Blue Spruce and Rocky Mountain
Acquisitions and Divestitures
2.  Conectiv Acquisition and Planned Divestiture of Blue Spruce and Rocky Mountain

Conectiv Acquisition

On July 1, 2010, we, through our indirect, wholly owned subsidiary NDH, completed the Conectiv Acquisition. The assets acquired include 18 operating power plants and one plant under construction, with approximately 4,490 MW of capacity (including completion of the York Energy Center under construction and scheduled upgrades). We did not acquire Conectiv’s trading book, load serving auction obligations or collateral requirements. Additionally, we did not assume any of Conectiv’s off-site environmental liabilities, environmental remediation liabilities related to certain assets located in New Jersey that are subject to the Industrial Site Recovery Act in excess of $10 million or certain pre-close pension and retirement welfare liabilities. Our final purchase price at closing was approximately $1.63 billion, including a $60 million reduction in the closing payment attributable to lower capital expenditures incurred by PHI than were scheduled and a $49 million increase in the closing payment for the estimated value of the fuel inventory at closing. As part of the Conectiv Acquisition, NDH received a cash contribution from Calpine Corporation of $110 million to fund future capital expenditures to complete the York Energy Center. We financed the transaction through available cash and bank debt of $1.3 billion provided under the NDH Project Debt. See Note 6 for further discussion of the NDH Project Debt.

The Conectiv Acquisition provides us with a significant presence in the PJM market, one of the most robust competitive power markets in the U.S., and positions us with three scale markets instead of two (CAISO and ERCOT) giving us greater geographic diversity.

We accounted for the Conectiv Acquisition under the acquisition method of accounting in accordance with GAAP; however, the assets acquired are not reflected on our Consolidated Condensed Balance Sheet as of June 30, 2010, as the Conectiv Acquisition occurred subsequent to our balance sheet date. We expensed transaction and acquisition-related costs as incurred through June 30, 2010 of approximately $19 million, which is included in sales, general and other administrative expense on our Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2010. As of the filing of this Report, the accounting for the Conectiv Acquisition is not complete as the appraisals necessary to assess the fair value of the net assets acquired are not final and we are still in the process of determining the tax basis of these assets; however, we conducted an assessment of our net assets acquired and assigned preliminary values to identifiable assets and liabilities at their estimated fair values on the acquisition date. We do not anticipate any significant goodwill will be recognized as a result of this acquisition.

The following table summarizes the consideration transferred for the Conectiv Acquisition and the preliminary values assigned to the net assets acquired as of the acquisition date based on our assessment (in millions). The preliminary values assigned are subject to change as more information is obtained about the fair value of the net assets acquired.

Consideration
 
$
1,634
 
         
Preliminary values of identifiable assets acquired and liabilities assumed:
       
Assets:
       
Current assets
 
$
80
 
Property, plant and equipment, net
   
1,556
 
Other long-term assets
   
50
 
Total assets acquired
 
$
1,686
 
Liabilities:
       
Current liabilities
 
$
30
 
Long-term liabilities
   
22
 
Total liabilities assumed
   
52
 
Net assets acquired
 
$
1,634
 

The following table summarizes the pro forma operating revenues and net income (loss) attributable to Calpine for the periods presented as if the Conectiv Acquisition had occurred on January 1, 2009 (in millions). The pro forma information has been prepared by adding the preliminary, unaudited historical results of Conectiv as adjusted for depreciation expense (utilizing the preliminary values assigned to the net assets acquired from Conectiv disclosed above), interest expense from our NDH Project Debt and income taxes.

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Operating revenues
  $ 2,213     $ 1,913     $ 4,330     $ 4,141  
Net loss attributable to Calpine
  $ (220   $ (130 )   $ (276 )   $ (118 )
Basic and diluted loss per common share attributable to Calpine
  $ (0.45 )   $ (0.27 )   $ (0.57 )   $ (0.24 )

Sale of Blue Spruce and Rocky Mountain

On April 2, 2010, we, through our wholly owned subsidiaries Riverside Energy Center, LLC and Calpine Development Holdings, Inc., entered into an agreement with PSCo to sell 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, subject to certain working capital adjustments at closing. Both power plants currently provide power and capacity to PSCo under PPAs, which materially expire in 2013 and 2014. Under the agreement, Riverside Energy Center, LLC and Calpine Development Holdings, Inc. will use commercially reasonable efforts to cause Blue Spruce and Rocky Mountain to continue to operate and maintain the power plants in the ordinary course of business through the closing of the transaction, which is expected to occur in December 2010. As of the filing of this Report, we have received all of the required Federal approvals for the sales of Blue Spruce and Rocky Mountain and we expect approval from the Colorado Public Utilities Commission in the third quarter of 2010. The transaction is expected to remove the restrictions on approximately $90 million in restricted cash at closing. We expect to use the sales proceeds received and the approximately $90 million in restricted cash described above to repay project debt (with an expected balance of approximately $412 million, after expected repayments prior to closing), for general corporate purposes and to focus more resources on our core markets. We expect to record a pre-tax gain of approximately $220 million upon closing this transaction.

The assets and liabilities of Blue Spruce and Rocky Mountain are reported as assets and liabilities held for sale on our Consolidated Condensed Balance Sheet at June 30, 2010. The results of operations of Blue Spruce and Rocky Mountain, which were included as part of our West segment, are reported as discontinued operations on our Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2010 and 2009.

The tables below present the components of assets and liabilities held for sale at June 30, 2010, and discontinued operations for the periods indicated (in millions):

   
June 30, 2010
 
Assets:
       
Current assets
 
$
14
 
Property, plant and equipment, net
   
516
 
Other long-term assets
   
18
 
Total assets held for sale
 
$
548
 
Liabilities:
       
Current liabilities
   
11
 
Long-term liabilities
   
2
 
Total liabilities held for sale
 
$
13
 

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Operating revenues
  $ 25     $ 26     $ 50     $ 51  
Income from discontinued operations before income taxes
  $ 12     $ 11     $ 20     $ 23  
Income tax expense
    8             8        
Discontinued operations, net of tax expense
  $ 4     $ 11     $ 12     $ 23  

Property Plant and Equipment, Net
Property, Plant and Equipment, Net
3.  Property, Plant and Equipment, Net

As of June 30, 2010, and December 31, 2009, the components of property, plant and equipment were stated at cost less accumulated depreciation as follows (in millions):

   
June 30, 2010
   
December 31, 2009
 
Buildings, machinery and equipment
  $ 13,281     $ 13,373  
Geothermal properties
    1,089       1,050  
Other
    244       232  
      14,614       14,655  
Less: Accumulated depreciation
    3,456       3,322  
      11,158       11,333  
Land
    71       74  
Construction in progress
    179       176  
Property, plant and equipment, net
  $ 11,408     $ 11,583  

Change in Depreciation Methods, Useful Lives and Salvage Values

As discussed in our 2009 Form 10-K and as described below, effective October 1, 2009, we made two changes to our methods of depreciation including (i) changing from composite depreciation to component depreciation for our rotable parts utilized in our natural gas-fired power plants and (ii) changing from the units of production method to the straight line method for our Geysers Assets. In addition, we completed a life study for each of our natural gas-fired power plants and our Geysers Assets, and changed our estimate of the remaining useful lives of our power plants and the useful lives and salvage values of our rotable parts utilized in our natural gas-fired power plants.

Component Depreciation for Rotable Parts at our Natural Gas-Fired Power Plants — During the three and six months ended June 30, 2009, we used the composite depreciation method for all of our natural gas-fired power plant assets. Under this method, all assets comprising each power plant were combined into one group and depreciated under a composite depreciation rate. Effective October 1, 2009, we componentized our rotable parts for our natural gas-fired power plant assets for purposes of calculating depreciation. The change in the method of depreciation for rotable parts was considered a change in accounting estimate inseparable from a change in accounting principle, and resulted in changes to our depreciation expense prospectively. The change to component depreciation for our rotable parts utilized in our natural gas-fired power plants also resulted in changes to the useful lives of our rotable parts which are now generally estimated to range from 3 to 18 years. Furthermore, we reduced our estimate of salvage value for our rotable parts to 0.15% of original cost to reflect our expectation with these separable parts. Prior to this change, our composite useful lives for our natural gas-fired power plant assets, including our rotable parts, were 35 years and 40 years for our combined-cycle and our simple-cycle power plant assets, respectively. We also revised the estimated useful lives of our remaining composite pools to 37 years and 47 years for our combined-cycle and simple-cycle power plant assets, respectively, based in part on the results of our separate useful life study. Our change in useful lives is considered a change in accounting estimate and resulted in changes to our depreciation expense prospectively.

Straight Line Method for our Geysers Assets — During the three and six months ended June 30, 2009, our Geysers Assets used the units of production method for depreciation. Our units of production depreciation rate was calculated using a depreciable base of the net book value of the Geysers Assets plus the expected future capital expenditures over the economic life of the geothermal reserves. The rate of depreciation per MWh was determined by dividing the depreciable base by total expected future generation. As a result of our change from the units of production method to the straight line method for our Geysers Assets, and based in part on the results of our separate useful life study, we revised our estimates of the remaining composite useful lives of our Geysers Assets effective October 1, 2009 to 59 years and 13 years for our Geysers steam extraction and gathering assets and our Geysers power plant assets, respectively. Our change in the method of depreciation for our Geysers Assets is considered a change in accounting estimate inseparable from a change in accounting principle, and resulted in changes to depreciation expense prospectively.
Variable Interest Entities And Unconsolidated Investments
Variable Interest Entities and Unconsolidated Investments
4.  Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. We have the following types of VIEs:

VIEs with a Purchase Option — We have six power plants with PPAs or other agreements that provide third parties the option to purchase power plant assets, an equity interest, or a portion of the future cash flows generated from an asset. The purchase options are exercisable only within a specified period of time upon expiration of the PPA or other agreements which expire at various dates occurring from 2011 – 2032.

Subsidiaries with Project Debt — Certain of our subsidiaries have project debt that contains provisions which we have determined create variability. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default, which we have determined to be unlikely. See Note 6 for further information regarding our project debt and Note 1 for information regarding our restricted cash balances.

Subsidiaries with PPAs — Certain of our wholly owned subsidiaries have PPAs that are deemed to be a form of subordinated financial support and thus constitute a VIE.

Other VIEs — Our other consolidated VIEs as of December 31, 2009, primarily consisted of monetized assets secured by financing for our PCF and PCF III subsidiaries. These financings were fully repaid during the first quarter of 2010 and are no longer VIEs.

New Accounting Standards and Disclosure Requirements for VIEs

Implementation — As further discussed in Note 1, new accounting standards became effective January 1, 2010 related to accounting for and consolidation of VIEs, which required us to perform an analysis of whether we are the primary beneficiary of our VIEs. The new standards generally replaced the quantitative-based risks and rewards calculation for determining which enterprise, if any, is the primary beneficiary of a VIE to a more qualitative assessment with an approach focused on identifying which enterprise has both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE.

As required, we performed an analysis of all of our VIEs effective January 1, 2010 and, with the exception of OMEC, our determination of the primary beneficiary did not change. We concluded that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our analysis to determine the primary beneficiary focused on determining which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis included consideration of the following primary activities which we believe to have a significant impact on a power plant’s financial performance: operations and maintenance, plant dispatch, fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights was based on powers held as of the balance sheet date. Contractual terms that will apply in future periods, such as a purchase or sale option, were not considered in our analysis. Based on our analysis, we determined that we hold the power and rights to direct the most significant activities of all our wholly owned VIEs.

OMEC — During the second quarter of 2007, we determined that SDG&E had a greater variability of risk compared to us based upon the prior consolidation accounting standards, which focused on which party held the greater variability in the obligation to absorb the losses or the right to receive benefits from the VIE or both. We determined that SDG&E held the greater variability as a result of a put option held by OMEC to sell the Otay Mesa Energy Center for $280 million to SDG&E, and a call option held by SDG&E to purchase the Otay Mesa Energy Center for $377 million in 2019. Accordingly, we were not the primary beneficiary, consolidation was not appropriate and we accounted for our investment in OMEC under the equity method of accounting through December 31, 2009.

The transfer of ownership in conjunction with the exercise of the put/call option, which was the driving factor in the quantitative determination of the primary beneficiary under the previous accounting standards, would not occur until 2019. Neither we, nor SDG&E, hold any powers under the combination put/call option as of January 1, 2010. Accordingly, we did not include the benefits and obligations of the put/call option in the new determination of the primary beneficiary under the current accounting standards. Based upon our analysis, we believe the significant activity that has the most impact on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we changed our determination of primary beneficiary from SDG&E to us effective January 1, 2010.
 
New Disclosures — Implementation of the new accounting standards also required separate disclosure on the face of our Consolidated Condensed Balance Sheet of the significant assets of a consolidated VIE that can only be used 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 separately.

In determining which assets of our VIEs met the separate disclosure criteria, we reviewed all of our VIEs and determined this separate disclosure requirement was met where Calpine Corporation was substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), where the VIE was not a guarantor or grantor under our primary debt facilities (our First Lien Credit Facility and First Lien Notes) and where there were prohibitions of the VIE under agreements that prohibited guaranteeing the debt of Calpine Corporation or its other subsidiaries and where the amounts were material to our financial statements. In determining which liabilities of our VIEs met the separate disclosure criteria, we reviewed all of our VIEs and determined this separate disclosure requirement was met where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others, where Calpine Corporation has not provided a corporate guarantee and where the amounts were material to our financial statements.

The VIEs meeting the above disclosure criteria are wholly owned subsidiaries of Calpine Corporation and include natural gas-fired power plants with an aggregate capacity of approximately 10,835 MW. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements between 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 and its other wholly owned subsidiaries did not provide any significant support in the form of cash contributions other than amounts contractually required during the three and six months ended June 30, 2010 and 2009.
 
Unconsolidated VIEs and Investments

We have a 50% partnership interest in Greenfield LP and a 50% equity interest in Whitby where we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP and Whitby are also VIEs. 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 as we exercise significant influence over their operating and financial policies. During 2009, we were not the primary beneficiary of OMEC and did not consolidate OMEC. Our equity interest in the net income from OMEC for the three and six months ended June 30, 2009, and both Greenfield LP and Whitby for the three and six months ended June 30, 2010 and 2009, are recorded in income from unconsolidated investments in power plants.

At June 30, 2010, and December 31, 2009, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):

   
Ownership
Interest as of
June 30, 2010
   
June 30, 2010
   
Our Maximum Exposure to Loss at June 30, 2010 (2)
   
December 31, 2009
 
OMEC(1)
    100%     $     $     $ 144  
Greenfield LP
    50%       85       85       70  
Whitby
    50%       4       4        
Total investments
          $ 89     $ 89     $ 214  
_________
 
(1)
OMEC was consolidated effective January 1, 2010. See Note 1.
 
(2)
Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. While we also could be responsible for our pro rata portion of debt, holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries. The debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. As of June 30, 2010, and December 31, 2009, equity method investee debt was approximately $488 million and $873 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $244 million and $624 million as of June 30, 2010 and December 31, 2009, respectively.

The following details our income from unconsolidated investments in power plants for the periods indicated (in millions):

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
OMEC(1)
  $     $ 16     $     $ 26  
Greenfield LP
    3       5       7       10  
Whitby
    3       2       6       4  
Total
  $ 6     $ 23     $ 13     $ 40  
__________
 
(1)
OMEC was consolidated effective January 1, 2010. See Note 1. During the three and six months ended June 30, 2009, we contributed $4 million and $8 million, respectively, as an additional investment in OMEC.

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 1,030 MW natural gas-fired power plant 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%.

Whitby — Represents our 50% equity interest in Whitby held by our Canadian subsidiaries. We received $2 million during the three and six months ended June 30, 2010, and nil and $2 million during the three and six months ended June 30, 2009, respectively, in distributions from Whitby.

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 began commercial operations on May 3, 2010) from General Electric International, Inc. that may be exercised between years 7 and 14 after the start of commercial operation. General Electric International, Inc. holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met during year 15 after the start of commercial operation. We determined that we were not the primary beneficiary of the Inland Empire power and we do not consolidate it due to, but not limited to, the fact that General Electric International, Inc. directs the most significant activities of the power plant.

Significant Subsidiaries — OMEC and Greenfield LP met the criteria of a significant subsidiary for the three and six months ended June 30, 2009, as defined under SEC guidelines, based upon the relationship of our equity income from our investment in each subsidiary to our consolidated loss before income taxes and discontinued operations. See Note 1 for further information regarding the OMEC consolidation effective January 1, 2010. The Condensed Statements of Operations for OMEC and for Greenfield LP for the periods indicated, are set forth below (in millions):

OMEC
Condensed Statements of Operations

   
Three Months
   
Six Months
 
   
Ended June 30,
   
Ended June 30,
 
   
2009
   
2009
 
Revenues(1)
  $     $  
Operating expenses
    1       2  
Loss from operations
    (1 )     (2 )
Interest income(2)
    (22 )     (33 )
Other (income) expense, net
    5       5  
Net income
  $ 16     $ 26  
__________
 
(1)
OMEC achieved commercial operations in October 2009.
 
(2)
Interest income is primarily the result of unrealized mark-to-market gains from interest rate swap contracts.

Greenfield LP
Condensed Statements of Operations

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Revenues
  $ 43     $ 43     $ 80     $ 103  
Operating expenses
    30       28       52       73  
Income from operations
    13       15       28       30  
Interest (income) expense, net
    7       7       14       11  
Other (income) expense, net
          (2 )           (1 )
Net income
  $ 6     $ 10     $ 14     $ 20  
 
Comprehensive Income (Loss)
Comprehensive Income (Loss)
5.  Comprehensive Income (Loss)

Comprehensive income (loss) includes our net loss, unrealized gains and losses from derivative instruments, net of tax that qualify as cash flow hedges, our share of equity method investees’ OCI and the effects of foreign currency translation adjustments. See Note 8 for further discussion of our accounting for derivative instruments designated as cash flow hedges and the related amounts recorded in OCI. We report AOCI on our Consolidated Condensed Balance Sheets. The table below details the components of our comprehensive income (loss) for the periods indicated (in millions):

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Net loss
  $ (114 )   $ (79 )   $ (162 )   $ (48 )
Other comprehensive income (loss):
                               
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss
    (71 )     108       30       310  
Reclassification adjustment for cash flow hedges realized in net loss
    8       (118 )     22       (185 )
Foreign currency translation gain (loss)
    (2 )     3             1  
Income tax benefit (expense)
    (23 )     14       (9 )     27  
Comprehensive income (loss)
    (202 )     (72 )     (119 )     105  
Add:  Comprehensive (income) loss attributable to the noncontrolling interest
    (1 )     1             2  
Comprehensive income (loss) attributable to Calpine
  $ (203 )   $ (71 )   $ (119 )   $ 107  
 
Debt
Debt
6.  Debt

Our debt at June 30, 2010, and December 31, 2009, was as follows (in millions):

   
June 30, 2010
   
December 31, 2009
 
First Lien Credit Facility(1)
  $ 4,230     $ 4,661  
First Lien Notes(1)
    1,600       1,200  
Commodity Collateral Revolver(2)
    100       100  
Project financing, notes payable and other
    2,384       2,289  
CCFC Notes
    962       959  
Capital lease obligations
    250       250  
Total debt
    9,526       9,459  
Less: Current maturities
    699       463  
Debt, net of current portion
  $ 8,827     $ 8,996  
__________
 
(1)
On July 23, 2010, we issued $1.1 billion of 2020 First Lien Notes and repaid approximately $1.1 billion of the First Lien Credit Facility term loans.
 
(2)
The Commodity Collateral Revolver was repaid on July 8, 2010.

First Lien Credit Facility — As of June 30, 2010, and December 31, 2009, our primary debt facility was our First Lien Credit Facility. Our First Lien Credit Facility includes an original $6.0 billion of senior secured term loans, a $1.0 billion senior secured revolving facility and, subject to market conditions, the ability to raise up to $2.0 billion of incremental term loans under an “accordion” provision available on a senior secured basis in order to refinance secured debt of subsidiaries. As of June 30, 2010, under our First Lien Credit Facility, we had approximately $4.2 billion outstanding under the term loans and $237 million of letters of credit issued against the revolver. Balances repaid under the senior secured term loans may not be reborrowed. Borrowings of term loans under our First Lien Credit Facility bear interest at a floating rate, at our option, of LIBOR plus 2.875% per annum or base rate plus 1.875% per annum. First Lien Credit Facility term loans require quarterly payments of principal equal to 0.25% of the original principal amount of First Lien Credit Facility term loans subject to adjustments as a result of First Lien Note offerings and repayments from excess cash flows. In May 2010, we repaid approximately $394 million and in July 2010, we repaid approximately $1.1 billion of the First Lien Credit Facility term loans with proceeds received from the issuance of the 2019 and 2020 First Lien Notes (as further discussed below). The First Lien Credit Facility matures on March 29, 2014.

The obligations under our First Lien Credit Facility are unconditionally guaranteed by certain of our direct and indirect domestic subsidiaries and are secured by a security interest in substantially all of the tangible and intangible assets of Calpine Corporation and certain of the guarantors. The obligations under our First Lien Credit Facility are also secured by a pledge of the equity interests of the direct subsidiaries of certain of the guarantors, subject to certain exceptions, including exceptions for equity interests in foreign subsidiaries, existing contractual prohibitions and prohibitions under other legal requirements. Our First Lien Credit Facility also requires compliance with financial covenants that include a maximum ratio of total net debt to Consolidated EBITDA (as defined in the First Lien Credit Facility), a minimum ratio of Consolidated EBITDA to cash interest expense, and a maximum ratio of total senior net debt to Consolidated EBITDA.

Issuance of 2019 First Lien Notes — On May 25, 2010, we issued $400 million in aggregate principal amount of 8% senior secured notes due 2019 in a private placement. The 2019 First Lien Notes were issued under an amended and restated indenture, dated as of May 25, 2010, among Calpine, the guarantors party thereto and Wilmington Trust Company, as trustee. The 2019 First Lien Notes bear interest at 8% payable semi-annually on February 15 and August 15 of each year beginning on August 15, 2010. Interest is due to the holders of record on February 1 and August 1 immediately preceding the applicable interest payment date. The 2019 First Lien Notes will mature on August 15, 2019. Proceeds received from the issuance of the 2019 First Lien Notes were used to repay approximately $394 million of the First Lien Credit Facility term loans on May 25, 2010. We recorded additional deferred financing costs of approximately $8 million on our Consolidated Condensed Balance Sheet and we recorded $7 million in debt extinguishment costs from the write-off of unamortized deferred financing costs related to the repayment of the First Lien Credit Facility term loans for the three and six months ended June 30, 2010.

Issuance of 2020 First Lien Notes — On July 23, 2010, we issued $1.1 billion in aggregate principal amount of 7.875% senior secured notes due 2020 in a private placement. The 2020 First Lien Notes were issued under an amended and restated indenture, dated as of July 23, 2010, among Calpine, the guarantors party thereto and Wilmington Trust Company, as trustee. The 2020 First Lien Notes bear interest at 7.875% payable semi-annually on January 31 and July 31 of each year beginning on January 31, 2011. Interest is due to the holders of record on January 15 and July 15 immediately preceding the applicable interest payment date. The 2020 First Lien Notes will mature on July 31, 2020. Proceeds received from the issuance of the 2020 First Lien Notes were used to repay approximately $1.1 billion of the First Lien Credit Facility term loans on July 23, 2010.

Our First Lien Notes are guaranteed by each of our current and future domestic subsidiaries that are guarantors under the First Lien Credit Facility and 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. Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Credit Facility and certain other indebtedness that is permitted to be secured by such assets by a first-priority lien, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets.

NDH Project Debt — On June 8, 2010, NDH entered into a credit agreement to fund the Conectiv Acquisition and the remaining capital expenditures to complete the York Energy Center under construction. Our NDH Project Debt includes a $1.3 billion seven-year senior secured term facility and a $100 million three-year senior secured revolving credit facility, of which up to $50 million will be available through a subfacility in the form of letters of credit. On July 1, 2010, the term facility was funded in the amount of $1.3 billion. The NDH Project Debt was issued with an original issue discount of $28 million and we recorded deferred financing costs of approximately $40 million, which we recorded on our Consolidated Condensed Balance Sheet on July 1, 2010. Our NDH Project Debt bears interest at a floating rate, at our option, at a rate per annum equal to the alternate base rate or the adjusted LIBOR (subject to a minimum of 1.5%), plus, in each case, the applicable margin, which varies for the revolving credit facility (as defined in our NDH Project Debt agreement). An amount equal to 0.25% of the aggregate principal amount of the senior secured term facility outstanding on July 1, 2010, which was $1.3 billion, will be payable at the end of each quarter commencing with the first full quarter after July 1, 2010, with the remaining balance payable on July 1, 2017. Additional repayments of principal will be required from excess cash flows (as defined in our NDH Project Debt agreement). No amortization will be required with respect to the revolving credit facility.

NDH’s obligations under the NDH Project Debt are unconditionally guaranteed by each existing and subsequently acquired or organized domestic, wholly owned subsidiary of NDH (including the entities acquired) and will be secured by a first-priority lien on substantially all of NDH’s and the guarantors’ existing and future assets, in each case subject to certain exceptions and permitted liens. NDH and its subsidiaries (subject to certain exceptions) have made certain representations and warranties and are required to comply with various affirmative and negative covenants including, among others, certain limitations and prohibitions relating to additional indebtedness, liens, restricted payments, mergers and asset sales and certain financial covenants relating to limitations on capital expenditures, minimum interest coverage and maximum leverage. The NDH Project Debt is 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. Neither Calpine Corporation nor any of its subsidiaries, other than NDH and its subsidiaries (subject to certain exceptions), are guarantors under the NDH Project Debt.

As part of the Conectiv Acquisition and NDH Project Debt, we entered into various intercompany agreements with our NDH subsidiaries for the related sales and purchases of power, natural gas and the operation and maintenance of our NDH power plants, which will not materially impact our results of operations, financial condition or cash flows on a consolidated basis. While there is no direct recourse by holders of the NDH Project Debt to Calpine Corporation, a substantial portion of the commodity price risk related to NDH’s power generation is absorbed by Calpine Energy Services, L.P. as an indirect, wholly owned subsidiary of Calpine Corporation, which purchases the power generated by NDH under an intercompany tolling agreement, which is also guaranteed by Calpine Corporation.

OMEC Debt — As further discussed in Note 1, we added approximately $375 million in project debt to our Consolidated Condensed Balance Sheet when we consolidated OMEC effective January 1, 2010. As of June 30, 2010, OMEC had approximately $370 million in project debt outstanding, which is included in the balance under the caption “Project financing, notes payable and other” in the table above. OMEC has a $377 million non-recourse project term loan which matures in April 2019. The term loan bears interest at LIBOR plus 1.25%.

Letter of Credit Facilities — The table below represents amounts issued under our letter of credit facilities as of June 30, 2010, and December 31, 2009 (in millions):

   
June 30, 2010
   
December 31, 2009
 
First Lien Credit Facility
  $ 237     $ 206  
Calpine Development Holdings, Inc.(1)
    135       116  
Various project financing facilities
    113       90  
Total
  $ 485     $ 412  
__________
 
(1)
Availability under the Calpine Development Holdings, Inc. letter of credit was increased by $50 million to $200 million on June 30, 2010.

Fair Value of Debt

We did not elect to apply the alternative GAAP provisions of the fair value option for recording financial assets and financial liabilities. We record our debt instruments based on contractual terms, net of any applicable premium or discount. We measured the fair value of our debt instruments as of June 30, 2010, and December 31, 2009, using market information including credit default swap rates and historical default information, quoted market prices or dealer quotes for the identical liability when traded as an asset and discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements. The following table details the fair values and carrying values of our debt instruments as of June 30, 2010, and December 31, 2009 (in millions):

   
June 30, 2010
   
December 31, 2009
 
   
Fair Value
   
Carrying Value
   
Fair Value
   
Carrying Value
 
First Lien Credit Facility(1)
  $ 3,871     $ 4,230     $ 4,402     $ 4,661  
First Lien Notes(1)
    1,564       1,600       1,138       1,200  
Commodity Collateral Revolver(2)
    92       100       94       100  
Project financing, notes payable and other(3)
    1,891       1,957       1,808       1,840  
CCFC Notes
    1,025       962       1,030       959  
Total
  $ 8,443     $ 8,849     $ 8,472     $ 8,760  
 _________
 
(1)
On July 23, 2010, we issued $1.1 billion of the 2020 First Lien Notes and repaid approximately $1.1 billion of the First Lien Credit Facility term loans.

(2)
The Commodity Collateral Revolver was repaid on July 8, 2010.
 
(3)
Excludes leases that are accounted for as failed sale-leaseback transactions under GAAP and included in our project financing, note payable and other balance.
Fair Value Measurements
Fair Value Measurements
7.  Fair Value Measurements

Derivatives — The primary factors affecting the fair value of our commodity derivative instruments at any point in time are the volume of open derivative positions (MMBtu and MWh); market price levels, principally for power and natural gas; our credit standing and that of our counterparties; and prevailing interest rates. Prices for power and natural gas 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 risks and 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; however, other qualitative assessments are used 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 the credit standing of our counterparties and the impact of credit enhancements, if any. We have included an estimate of nonperformance risk 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 and swaps for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from markets and pricing services 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 such 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 primarily consist of our 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 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.

Margin Deposits — Our margin deposits are cash and cash equivalents and are generally classified within level 1 of the fair value hierarchy as the amounts approximate fair value.

The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010, and December 31, 2009, 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, 2010  
   
Level 1
   
Level 2
   
Level 3
   
Total
 
   
(in millions)
 
Assets:
                       
Cash equivalents(1)
  $ 1,148     $     $     $ 1,148  
Margin deposits(2)
    254                   254  
Commodity instruments:
                               
Commodity futures contracts
    1,012                   1,012  
Commodity forward contracts(3)
          383       68       451  
Interest rate swaps
                       
Total assets
  $ 2,414     $ 383     $ 68     $ 2,865  
                                 
Liabilities:
                               
Margin deposits held by us posted by our counterparties(2)
  $ 58     $     $     $ 58  
Commodity instruments:
                               
Commodity futures contracts
    1,003                   1,003  
Commodity forward contracts(3)
          182       25       207  
Interest rate swaps
          416             416  
Total liabilities
  $ 1,061     $ 598     $ 25     $ 1,684  


   
Assets and Liabilities with Recurring Fair Value Measures
 
    as of December 31, 2009  
   
Level 1
   
Level 2
   
Level 3
   
Total
 
   
(in millions)
 
Assets:
                       
Cash equivalents(1)
  $ 1,306     $     $     $ 1,306  
Margin deposits(2)
    413                   413  
Commodity instruments:
                               
Commodity futures contracts
    953                   953  
Commodity forward contracts(3)
          204       71       275  
Interest rate swaps
          18             18  
Total assets
  $ 2,672     $ 222     $ 71     $ 2,965  
                                 
Liabilities:
                               
Margin deposits held by us posted by our counterparties(2)
  $ 9     $     $     $ 9  
Commodity instruments:
                               
Commodity futures contracts
    1,096                   1,096  
Commodity forward contracts(3)
          91       33       124  
Interest rate swaps
          337             337  
Total liabilities
  $ 1,105     $ 428     $ 33     $ 1,566  
__________
 
(1)
Represents funds invested in money market accounts and are included in cash and cash equivalents and restricted cash on our Consolidated Condensed Balance Sheets. As of June 30, 2010, and December 31, 2009, we had cash equivalents of $833 million and $770 million included in cash and cash equivalents and $315 million and $536 million included in restricted cash, respectively.
 
(2)
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.
 
(3)
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,
 
   
2010
   
2009
   
2010
   
2009
 
Balance, beginning of period
 
$
57
   
$
114
   
$
38
   
$
105
 
Realized and unrealized gains (losses):
                               
Included in net loss:
                               
Included in operating revenues(1)
   
10
     
(1
)
   
29
     
3
 
Included in fuel and purchased energy expense(2)
   
(3
)
   
(3
)
   
(3
)
   
8
 
Included in OCI
   
(5
)
   
5
     
     
18
 
Purchases, issuances, sales and settlements:
                               
Settlements
   
(16
)
   
(13
)
   
(22
)
   
(26
)
Transfers into and/or out of level 3(3):
                               
Transfers into level 3(4)
   
     
     
     
(6
)
Transfers out of level 3(5)
   
     
(11
)
   
1
     
(11
)
Balance, end of period
 
$
43
   
$
91
   
$
43
   
$
91
 
                                 
Change in unrealized gains and (losses) relating to instruments still held at end of period
 
$
7
   
$
(4
)
 
$
26
   
$
11
 
__________
 
(1)
For power contracts and Heat Rate swaps and options, as shown on our Consolidated Condensed Statements of Operations.
 
(2)
For natural gas contracts, swaps and options, as shown 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 significant transfers into/out of level 1 during the three and six months ended June 30, 2010 and 2009.
 
(4)
There were no significant transfers into level 3 for the three months ended June 30, 2010 and 2009, and the six months ended June 30, 2010. We had $(6) million in losses transferred out of level 2 into level 3, for the six months ended June 30, 2009, due to changes in market liquidity in various power markets.
 
(5)
There were no significant transfers out of level 3 for the three months ended June 30, 2010; however, we had $11 million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2009. We had $(1) million in losses and $11 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2010 and 2009, respectively. Transfers out of level 3 into level 2 were due to changes in market liquidity in various power markets.
Derivative Instruments
Derivative Instruments
8.  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 enter into a variety of derivative instruments, including 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) for the purchase and sale of power, natural gas, and emission allowances to attempt to economically hedge a portion of the commodity price risk associated with our assets and thus maximize risk-adjusted returns. 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 significant portion of our debt is indexed to base rates, primarily LIBOR. We use interest rate swaps to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. These transactions primarily act as economic hedges for our interest cash flow.

As of June 30, 2010, the maximum length of our PPAs extends approximately 22 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 3 and 16 years, respectively.

As of June 30, 2010, and December 31, 2009, 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):

     
Notional Amounts
 
Derivative Instruments
   
June 30, 2010
   
December 31, 2009
 
Power (MWh)      (49      (52
Natural gas (MMBtu)
   
87
     
78
 
Interest rate swaps
 
$
5,824
   
$
7,324
 
 
Certain of our derivative instruments contain credit-contingent provisions that require us to maintain our current credit rating or higher from each of the major credit rating agencies. 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 a counterparty would request full and immediate settlement or that any additional collateral posted as a result of a credit rating downgrade would be material. The aggregate fair value of our derivative liabilities with credit-contingent provisions as of June 30, 2010, was $23 million for which we have posted collateral of $4 million by posting margin deposits or granted additional first priority liens on the assets currently subject to first priority liens under our First Lien Credit Facility.

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 settlement dates. Revenues and fuel costs derived from instruments that qualify for hedge accounting are recorded in the same period and 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 within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.

Cash Flow Hedges — We 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 commodity hedging instruments are included in unrealized mark-to-market gains and losses, and 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). 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 OCI 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 — Along with our portfolio of transactions which are accounted for as hedges under GAAP, we enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset 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).
 
Derivatives Included on Our Consolidated Condensed Balance Sheets

The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by hedge type and location at June 30, 2010, and December 31, 2009 (in millions):
 
   
June 30, 2010
 
               
Total
 
Balance Sheet Presentation
 
Interest Rate
   
Commodity
   
Derivative
 
 
Swaps
   
Instruments
   
Instruments
 
Current derivative assets
  $     $ 1,240     $ 1,240  
Long-term derivative assets
          223       223  
Total derivative assets
  $     $ 1,463     $ 1,463  
                         
Current derivative liabilities
  $ 181     $ 1,063     $ 1,244  
Long-term derivative liabilities
    235       147       382  
Total derivative liabilities
  $ 416     $ 1,210     $ 1,626  
Net derivative assets (liabilities)
  $ (416 )   $ 253     $ (163 )

   
December 31, 2009
 
               
Total
 
Balance Sheet Presentation
 
Interest Rate
   
Commodity
   
Derivative
 
 
Swaps
   
Instruments
   
Instruments
 
Current derivative assets
  $     $ 1,119     $ 1,119  
Long-term derivative assets
    18       109       127  
Total derivative assets
  $ 18     $ 1,228     $ 1,246  
                         
Current derivative liabilities
  $ 202     $ 1,158     $ 1,360  
Long-term derivative liabilities
    135       62       197  
Total derivative liabilities
  $ 337     $ 1,220     $ 1,557  
Net derivative assets (liabilities)
  $ (319 )   $ 8     $ (311 )

   
June 30, 2010
 
   
Fair Value
   
Fair Value
 
   
of Derivative
   
of Derivative
 
   
Assets
   
Liabilities
 
Derivatives designated as cash flow hedging instruments:
           
Interest rate swaps
  $     $ 368  
Commodity instruments
    331       109  
Total derivatives designated as cash flow hedging instruments
  $ 331     $ 477  
                 
Derivatives not designated as hedging instruments:
               
Interest rate swaps
  $     $ 48  
Commodity instruments
    1,132       1,101  
Total derivatives not designated as hedging instruments
  $ 1,132     $ 1,149  
Total derivatives
  $ 1,463     $ 1,626  

   
December 31, 2009
 
   
Fair Value
   
Fair Value
 
   
of Derivative
   
of Derivative
 
   
Assets
   
Liabilities
 
Derivatives designated as cash flow hedging instruments:
           
Interest rate swaps
 
$
18
   
$
324
 
Commodity instruments
   
213
     
80
 
Total derivatives designated as cash flow hedging instruments
 
$
231
   
$
404
 
                 
Derivatives not designated as hedging instruments:
               
Interest rate swaps
 
$
   
$
13
 
Commodity instruments
   
1,015
     
1,140
 
Total derivatives not designated as hedging instruments
 
$
1,015
   
$
1,153
 
Total derivatives
 
$
1,246
   
$
1,557
 

 
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 net loss.

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 not designated as hedging instruments 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,
 
   
2010
   
2009
   
2010
   
2009
 
Realized gain (loss)
                       
Interest rate swaps
  $ (6 )   $ (4 )   $ (12 )   $ (8 )
Commodity instruments
    59       44       52       (14 )
Total realized gain (loss)
  $ 53     $ 40     $ 40     $ (22 )
                                 
Unrealized gain (loss) (1)
                               
Interest rate swaps
  $ (16 )   $ 4     $ (19 )   $ 4  
Commodity instruments
    (31 )     (108 )     81       17  
Total unrealized gain (loss)
  $ (47 )   $ (104 )   $ 62     $ 21  
Total mark-to-market activity
  $ 6     $ (64 )   $ 102     $ (1 )

__________
 
(1)
Changes in unrealized gains and losses include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Realized and unrealized gain (loss)
                       
Power contracts included in operating revenues
  $ 41     $ (49 )   $ 12     $ (9 )
Natural gas contracts included in fuel and purchased energy expense
    (13 )     (15 )     121       12  
Interest rate swaps included in interest expense
    (22 )           (31 )     (4 )
Total mark-to-market activity
  $ 6     $ (64 )   $ 102     $ (1 )


Derivatives Included in OCI and AOCI

The following tables detail the effect of our net derivative instruments that qualify for hedge accounting treatment and included in OCI and AOCI for the periods indicated (in millions):
 
   
Three Months Ended June 30,
 
   
2010
 
2009
 
2010
 
2009
 
2010
 
2009
 
   
Gain (Loss) Recognized in
 
Gain (Loss) Reclassified from AOCI
 
Gain (Loss) Reclassified from AOCI
 
   
OCI (Effective Portion)
 
into Income (Effective Portion)
 
into Income (Ineffective Portion)
 
Interest rate swaps
 
$
(16
)
$
80
 
$
(62
) (1)
$
(48
)(1)  
$
(1)
$
 
Commodity instruments
   
(47
)
 
(90
)
 
54
(2)   
 
166
(2)   
 
3
(2)
 
(1
)(2)
Total
 
$
(63
)
$
(10
)
$
(8
)
$
118
 
$
3
 
$
(1
)

   
Six Months Ended June 30,
 
   
2010
 
2009
 
2010
 
2009
 
2010
 
2009
 
   
Gain (Loss) Recognized in
 
Gain (Loss) Reclassified from AOCI
 
Gain (Loss) Reclassified from AOCI
 
   
OCI (Effective Portion)
 
into Income (Effective Portion)
 
into Income (Ineffective Portion)
 
Interest rate swaps
 
$
(27
)
$
87
 
$
(122
)(1)
$
(92
)(1)   
$
(1)
$
 
Commodity instruments
   
79
   
38
   
100
(2)   
 
277
(2)   
 
1
(2)
 
 
Total
 
$
52
 
$
125
 
$
(22
)
$
185
 
$
1
 
$
 
__________
 
(1)
Included in interest expense on our Consolidated Condensed Statements of Operations.
 
(2)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

Assuming constant June 30, 2010 power and natural gas prices and interest rates, we estimate that pre-tax net losses of $3 million 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 natural gas and power prices as well as interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI to earnings (positive or negative) will be for the next 12 months. As of June 30, 2010, approximately $70 million in unrealized losses were recorded in AOCI for interest rate swaps that were hedging the variable interest rates on approximately $1.1 billion of First Lien Credit Facility term loans, which were repaid with the proceeds received from the issuance of the 2020 First Lien Notes on July 23, 2010 (see Note 6 for further discussion of our issuance of the 2020 First Lien Notes). These interest rate swaps will no longer qualify as cash flow hedges and the corresponding amounts will be reclassified into earnings during the third quarter of 2010 as additional interest expense. Additionally, prospective changes in the fair value of these interest rate swaps will also be recorded in earnings as interest expense.
 
Use of Collateral
Use Of Collateral
9.  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 our First Lien Credit Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under our First Lien Credit Facility 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 would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Credit Facility.

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, 2010, and December 31, 2009 (in millions):

   
June 30, 2010
   
December 31, 2009
 
Margin deposits(1)
  $ 254     $ 413  
Natural gas and power prepayments
    42       34  
Total margin deposits and natural gas and power prepayments with our counterparties(2)
  $ 296     $ 447  
                 
Letters of credit issued
  $ 391     $ 353  
First priority liens under power and natural gas agreements(3)
           
First priority liens under interest rate swap agreements
    405       333  
Total letters of credit and first priority liens with our counterparties
  $ 796     $ 686  
                 
Margin deposits held by us posted by our counterparties(1)(4)
  $ 58     $ 9  
Letters of credit posted with us by our counterparties
    57       70  
Total margin deposits and letters of credit posted with us by our counterparties
  $ 115     $ 79  
__________
 
(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, 2010, and December 31, 2009, $275 million and $426 million were included in margin deposits and other prepaid expense, respectively, and $21 million were included in other assets at both June 30, 2010 and December 31, 2009 on our Consolidated Condensed Balance Sheets.
 
(3)
At June 30, 2010, and December 31, 2009, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $253 million and $123 million, respectively; therefore, there was no collateral exposure at June 30, 2010, or December 31, 2009.
 
(4)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.

Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.

Income Taxes
Income Taxes
10.  Income Taxes

For federal income tax reporting purposes, our consolidated GAAP financial reporting group is comprised primarily of two separate tax reporting groups, CCFC and its subsidiaries, which we refer to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we refer to as the Calpine group. In 2005, CCFCP issued the CCFCP Preferred Shares, which resulted in the deconsolidation of the CCFC group for income tax purposes. On July 1, 2009, the CCFCP Preferred Shares were redeemed; however, CCFCP continues to be a partnership and therefore, the CCFC group remains deconsolidated from Calpine Corporation for federal income tax reporting purposes. As of June 30, 2010, the CCFC group did not have a valuation allowance recorded against its deferred tax assets, whereas the Calpine group continued to have a valuation allowance. For the three and six months ended June 30, 2010 and 2009, we used the effective rate method to determine both the CCFC and Calpine groups’ tax provision; however, our income tax rates did not bear a customary relationship to statutory income tax rates primarily as a result of the impact of state income taxes, changes in unrecognized tax benefits, the Calpine group valuation allowance and intraperiod tax allocations discussed below. Our consolidated income tax expense from continuing operations and imputed tax rate was approximately $6 million and (5)% and approximately $15 million and (20)% for the three months ended June 30, 2010 and 2009, respectively, and approximately $17 million and (11)% and approximately $24 million and (53)% for the six months ended June 30, 2010 and 2009, respectively. Our income tax expense from continuing operations included an intraperiod tax allocation (benefit) expense of a net ($31) million and $14 million for the three months ended June 30, 2010 and 2009, respectively, and a net ($16) million, which includes approximately $13 million in tax expense related to a prior period, and $27 million for the six months ended June 30, 2010 and 2009, respectively, with an offsetting tax expense (benefit) allocated between discontinued operations or OCI in each respective period.

Valuation Allowance — 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. In prior periods, we provided a valuation allowance on certain federal, state and foreign tax jurisdiction deferred tax assets of the Calpine group to reduce the gross amount of these assets to the extent necessary to result in an amount that is more likely than not of being realized. Projected future income from reversals of existing taxable temporary differences and tax planning strategies allowed a larger portion of the deferred tax assets to be offset against deferred tax liabilities resulting in a significant release of previously recorded valuation allowance in prior periods; however, we have not released any additional previously recorded valuation allowance in 2010.

Income Tax Audits — In September 2009, we received notice from the Canadian Revenue Authority (“CRA”) of their intent to conduct a limited scope income tax audit on four of our Canadian subsidiaries for the tax years ending 2005 through 2008. We have timely responded to their request for information and received notice from the CRA that they have completed their audit of transactions within Canada and no changes were proposed. The CRA international audit division continues to review cross border transactions within the audit period. At this time, we are unable to determine the likelihood of a material adverse assessment.

We remain subject to other various audits and reviews by state 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 2006 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.

Unrecognized Tax Benefits and Liabilities — As of June 30, 2010, we had unrecognized tax benefits of $87 million. If recognized within the next 12 months, $40 million of our unrecognized tax benefits could impact the annual effective tax rate and $47 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 $18 million for income tax matters as of June 30, 2010. The amount of unrecognized tax benefits decreased by $11 million for the six months ended June 30, 2010, primarily as a result of $9 million related to a hedging position terminated for CCFC group and $2 million related to depreciation taken on a position for a capitalized asset. The decrease related to temporary differences in tax reporting and did not impact the annual effective tax rate. We believe it is reasonably possible that a decrease of approximately $1 million in unrecognized tax benefits could occur within the next 12 months primarily related to state tax liabilities and state interest and penalties.

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 Internal Revenue Code. 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. If a subsequent ownership change were to occur as a result of future transactions in our 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. The Calpine group adjusted its NOL for prior periods through December 31, 2009, increasing it by approximately $175 million. These adjustments consisted of $49 million to reduce the NOL for excluded cancellation of debt income, a $230 million increase in prior period NOLs for development costs and construction in progress relating to abandoned projects and other decreases of $6 million.
 
To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock in the following circumstances: 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 Internal Revenue Code. We believe as of the filing of this Report, neither circumstance was met. While we do not believe an ownership change of 25 percentage points has occurred, the change in ownership is only slightly less than 25%. 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 were 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.
 
Should our Board of Directors elect to impose these restrictions, they shall 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.

Loss Per Share
Earnings Per Share
11.  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, are unresolved. To the extent that any of the reserved shares remain undistributed upon resolution of the disputed claims, such shares will not be returned to us but rather will be distributed pro rata to claimants with allowed claims to increase their recovery. Therefore, pursuant to our Plan of Reorganization, all 485 million shares ultimately will be distributed. Accordingly, although the reserved shares are not yet issued and outstanding, 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, 2010 and 2009, diluted loss per share for those 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 potentially dilutive securities from our calculation of weighted average shares outstanding from diluted loss per common share for the periods indicated:

   
Three Months Ended June 30,
 
Six Months Ended June 30,
 
   
2010
 
2009
 
2010
 
2009
 
   
(shares in thousands)
 
Share-based awards
   
15,000
   
13,539
   
14,655
   
13,808
 

Stock-Based Compensation
Stock-Based Compensation
12.  Stock-Based Compensation

The Calpine Equity Incentive Plans were approved as part of our Plan of Reorganization. These plans are administered by the Compensation Committee of our Board of Directors and provide for the issuance of equity awards to all 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.

On May 19, 2010, our shareholders, upon the recommendation of our Board of Directors, approved the amendment to the Director Plan to increase the aggregate number of shares of common stock authorized for issuance under the Director Plan by 400,000 shares and to extend the term of the Director Plan to January 31, 2018, and approved the amendment to the Equity Plan to increase the aggregate number of shares of common stock authorized for issuance under the Equity Plan by 12,700,000 shares. Subsequent to the amendments of the Calpine Equity Incentive Plans, there are 567,000 and 27,533,000 shares, respectively, of our common stock authorized for issuance to participants.

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 of seven and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. Employment inducement options to purchase a total of 4,636,734 shares were granted outside of the Calpine Equity Incentive Plans in connection with the hiring of our Chief Executive Officer and our Chief Legal Officer in August 2008, and our Chief Commercial Officer in September 2008; however, no grants of options or shares of restricted stock were made outside of the Calpine Equity Incentive Plans during the six months ended June 30, 2010 and 2009.

We use the Black-Scholes option-pricing model to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected life 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 $6 million and $9 million for the three months ended June 30, 2010 and 2009, respectively, and $12 million and $22 million for the six months ended June 30, 2010 and 2009, respectively. We did not record any tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the three and six months ended June 30, 2010 and 2009. At June 30, 2010, there was unrecognized compensation cost of $23 million related to options, $17 million related to restricted stock and $1 million related to restricted stock units, which is expected to be recognized over a weighted average period of 1.7 years for options, 2.1 years for restricted stock and 0.9 years for restricted stock units. We issue new shares from our 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, 2010, is as follows:

         
Weighted
     
         
Average
     
     
Weighted
 
Remaining
 
Aggregate
 
 
Number of
 
Average
 
Term
 
Intrinsic Value
 
 
Options
 
Exercise Price
 
(in years)
 
(in millions)
 
Outstanding – December 31, 2009
13,232,519
 
$
19.09
 
6.6
 
$
2
 
Granted
1,051,791
 
$
11.27
           
Exercised
810
 
$
8.84
           
Forfeited
176,272
 
$
13.14
           
Expired
181,586
 
$
17.37
           
Outstanding – June 30, 2010
13,925,642
 
$
18.60
 
6.3
 
$
5
 
Exercisable – June 30, 2010
4,643,082
 
$
18.61
 
6.6
 
$
 
Vested and expected to vest – June 30, 2010
13,514,809
 
$
18.81
 
6.2
 
$
4
 



The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the six months ended June 30, 2010. There were no employee stock options exercised during the six months ended June 30, 2009.

The fair value of options granted during the six months ended June 30, 2010 and 2009, was determined on the grant date using the Black-Scholes pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.

   
2010
   
2009
 
Expected term (in years)(1)
    6.5       6.0 – 6.5  
Risk-free interest rate(2)
    2.9 – 3.3 %     2.3 – 2.9 %
Expected volatility(3)
    35.0 – 37.6 %     60.1 – 73.0 %
Dividend yield(4)
           
Weighted average grant-date fair value (per option)
  $ 4.66     $ 5.66  
__________
 
(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 are currently prohibited under our First Lien Credit Facility and certain of our other debt agreements from paying any cash dividends on our common stock.

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, 2010, is as follows:

     
Weighted
 
 
Number of
 
Average
 
 
Restricted
 
Grant-Date
 
 
Stock Awards
 
Fair Value
 
Nonvested – December 31, 2009
2,046,599
 
$
11.95
 
Granted
1,474,410
 
$
11.32
 
Forfeited
209,745
 
$
10.96
 
Vested
428,422
 
$
15.54
 
Nonvested – June 30, 2010
2,882,842
 
$
11.17
 

The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2010 and 2009, was $4 million and $6 million, respectively.

Segment Information
Segment Information

13.  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, 2010, our reportable segments were West (including geothermal), Texas, Southeast and North (including Canada). We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.

Commodity Margin includes our power and steam revenues, sales of purchased power and natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenues. 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). Our West segment has been recast for all periods presented to exclude results for Blue Spruce and Rocky Mountain, which have been reported as discontinued operations. See Note 2 for further discussion of our discontinued operations.

   
Three Months Ended June 30, 2010
 
                           
Consolidation
       
                           
and
       
   
West
   
Texas
   
Southeast
   
North
   
Elimination
   
Total
 
Revenues from external customers
  $ 525     $ 552     $ 219     $ 134     $     $ 1,430  
Intersegment revenues
    1       6       21       1       (29 )      
Total operating revenues
  $ 526     $ 558     $ 240     $ 135     $ (29 )   $ 1,430  
Commodity Margin
  $ 258     $ 128     $ 68     $ 79     $     $ 533  
Add: Mark-to-market commodity activity, net and other revenue(1)
    10       (10 )     (9 )     3       (6 )     (12 )
Less:
                                               
Plant operating expense
    88       78       31       23       (7 )     213  
Depreciation and amortization expense
    50       39       26       18       (1 )     132  
Other cost of revenue(2)
    10       (5 )           7       7       19  
Gross profit
    120       6       2       34       (5 )     157  
Other operating expenses
    13       17       2       17             49  
Income (loss) from operations
    107       (11 )           17       (5 )     108  
Interest expense, net of interest income
                                            212  
Debt extinguishment costs and other (income) expense, net
                                            8  
Loss before income taxes and discontinued operations
                                          $ (112 )
 
 
   
Three Months Ended June 30, 2009
 
                           
Consolidation
       
                           
and
       
   
West
   
Texas
   
Southeast
   
North
   
Elimination
   
Total
 
Revenues from external customers
  $ 764     $ 371     $ 177     $ 133     $     $ 1,445  
Intersegment revenues
    7       18       20       2       (47 )      
Total operating revenues
  $ 771     $ 389     $ 197     $ 135     $ (47 )   $ 1,445  
Commodity Margin
  $ 278     $ 196     $ 80     $ 70     $     $ 624  
Add: Mark-to-market commodity activity, net and other revenue(1)
    57       (140 )     (25 )     14       (9 )     (103 )
Less:
                                               
Plant operating expense
    96       50       35       23       2       206  
Depreciation and amortization expense
    47       31       17       15       (2 )     108  
Other cost of revenue(2)
    12       2       1       7       (4 )     18  
Gross profit (loss)
    180       (27 )     2       39       (5 )     189  
Other operating expenses
    1       21       8                   30  
Income (loss) from operations
    179       (48 )     (6 )     39       (5 )     159  
Interest expense, net of interest income
                                            199  
Debt extinguishment costs and other (income) expense, net
                                            32  
Loss before reorganization items, income taxes and discontinued operations
                                            (72 )
Reorganization items
                                            3  
Loss before income taxes and discontinued operations
                                          $ (75 )


   
Six Months Ended June 30, 2010
 
                           
Consolidation
       
                           
and
       
   
West
   
Texas
   
Southeast
   
North
   
Elimination
   
Total
 
Revenues from external customers
  $ 1,190     $ 1,079     $ 418     $ 257     $     $ 2,944  
Intersegment revenues
    5       10       44       2       (61 )      
Total operating revenues
  $ 1,195     $ 1,089     $ 462     $ 259     $ (61 )   $ 2,944  
Commodity Margin
  $ 471     $ 235     $ 126     $ 131     $     $ 963  
Add: Mark-to-market commodity activity, net and other revenue(1)
    18       86       13             (14 )     103  
Less:
                                               
Plant operating expense
    178       162       59       45       (13 )     431  
Depreciation and amortization expense
    101       74       55       38       (3 )     265  
Other cost of revenue(2)
    25       1       2       14       (2 )     40  
Gross profit
    185       84       23       34       4       330  
Other operating expenses
    32       19       7       14             72  
Income from operations
    153       65       16       20       4       258  
Interest expense, net of interest income
                                            402  
Debt extinguishment costs and other (income) expense, net
                                            13  
Loss before income taxes and discontinued operations
                                          $ (157 )

 
   
Six Months Ended June 30, 2009
 
                                  Consolidation        
                                  and        
   
West
     
Texas
     
Southeast
   
North
      Elimination    
Total
 
Revenues from external customers
 
$
1,626
    $
856
    $
351
     $
264
    $
    $
3,097
 
Intersegment revenues
   
17
     
53
     
55
     
13
     
(138
)
   
 
Total operating revenues
 
$
1,643
    $
909
    $
406
     $
277
    $
(138
)
  $
3,097
 
Commodity Margin
 
$
550
     $
318
    $
141
      $
119
     $
    $
1,128
 
Add: Mark-to-market commodity activity, net and other revenue(1)
   
79
     
(50
)
   
6
     
16
     
(23
)
   
28
 
Less:
                                               
Plant operating expense
   
218
     
128
     
67
     
43
     
(7
)
   
449
 
Depreciation and amortization expense
   
92
     
61
     
33
     
31
     
(4
)
   
213
 
Other cost of revenue(2)
   
27
     
5
     
4
     
13
     
(10
)
   
39
 
Gross profit
   
292
     
74
     
43
     
48
     
(2
)
   
455
 
Other operating expenses
   
13
     
37
     
15
     
(3
)
   
     
62
 
Income from operations
   
279
     
37
     
28
     
51
     
(2
)
   
393
 
Interest expense, net of interest income
                                           
399
 
Debt extinguishment costs and other (income) expense, net
                                           
35
 
Loss before reorganization items, income taxes and discontinued operations
                                           
(41
)
Reorganization items
                                           
6
 
Loss before income taxes and discontinued operations
                                         
$
(47
)
__________
 
(1)
Mark-to-market commodity activity represents 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.
 
(2)
Excludes $5 million and $2 million of RGGI compliance and other environmental costs for the three months ended June 30, 2010 and 2009, respectively, and $5 million and $4 million for the six months ended June 30, 2010 and 2009, respectively, which are included as a component of Commodity Margin.

Commitments and Contingencies
Commitments and Contingencies
14.  Commitments and Contingencies

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result of these matters, may potentially be material to our financial position or results of operations. We review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by GAAP. Where we have determined an unfavorable outcome is probable and is reasonably estimable, we have accrued for potential litigation losses. Following the Effective Date, pending actions to enforce or otherwise effect repayment of liabilities preceding December 20, 2005, the petition date, as well as pending litigation against the U.S. Debtors related to such liabilities, generally have been permanently enjoined. Any unresolved claims will continue to be subject to the claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain pending litigation related to pre-petition liabilities may proceed in courts other than the U.S. Bankruptcy Court to the extent the parties to such litigation have obtained relief from the permanent injunction. In particular, certain pending actions against us are anticipated to proceed as described below. In addition to the matters described below, we are involved in various other claims and legal actions, including regulatory and administrative proceedings arising out of the normal course of our business. We do not expect that the outcome of such other claims and legal actions will have a material adverse effect on our financial position or results of operations.

Pit River Tribe, et al. v. Bureau of Land Management, et al. — On June 17, 2002, the Pit River Tribe filed suit against the BLM and other federal agencies in the U.S. District Court for the Eastern District of California (“District Court”), seeking to enjoin further exploration, construction and development of the Calpine Fourmile Hill Project in the Glass Mountain and Medicine Lake geothermal areas. Its complaint challenged the validity of the decisions of the BLM and the U.S. Forest Service to permit the development of the proposed project under two geothermal mineral leases previously issued by the BLM. The lawsuit also sought to invalidate the leases. Only declaratory and equitable relief was sought.

On November 5, 2006, the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”) issued a decision granting the plaintiffs relief by holding that the BLM had not complied with the National Environmental Policy Act and other procedural requirements and, therefore, held that the lease extensions were invalid. The Ninth Circuit remanded the matter back to the District Court to implement its decision. On December 22, 2008 the District Court in turn remanded this matter back to federal agencies for curative action, including whether the leases may be extended. Before the agencies could reconsider, the Pit River Tribe appealed the District Court’s decision on the basis the original Ninth Circuit decision purportedly invalidated the leases, and therefore, the Pit River Tribe argues, the Ninth Circuit did not give the District Court latitude to grant an extension of the leases. Oral argument on the Tribe’s appeal was held in the Ninth Circuit on March 10, 2010. We anticipate a decision from the Ninth Circuit during the third quarter of 2010.

In addition, the Pit River Tribe and other interested parties filed two separate suits in the District Court seeking to enjoin exploration, construction, and development of the Telephone Flat leases and proposed project at Glass Mountain in May 2004. These two related cases continue to be subject to the discharge injunction as described in the Confirmation Order. Similar to above, we are now in communication with the U.S. Department of Justice regarding these two cases; but, the cases remain mostly inactive pending the outcome of the above described Pit River Tribe case.

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 normal operation of our power plants. We do not, however, 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 of our power plants. A summary of our larger environmental matters is as follows:

Texas City and Clear Lake Environmental Matters — As part of an internal review of our Texas City and Clear Lake power plants, we determined that these power plants were in violation of the requirements of the Acid Rain Program found in Title 40 of the U.S. Federal Code of Regulations Parts 72-78. These power plants were originally exempt from these provisions because each plant was a qualifying cogeneration power plant in operation before November 1990 with qualifying original PPAs in place. However, the PPAs expired in 2002 for our Texas City power plant and in 1999 for our Clear Lake power plant. To remedy the violations, the power plants were required to retire the number of SO2 emission allowances equal to actual SO2 emitted since the expiration of the exemption and remit an excess emission fee for each ton of SO2 emitted during the period of non-compliance. We self-reported the excess emissions to the TCEQ and the EPA. Compliance agreements between each power plant and the TCEQ were executed on September 26, 2008, which shielded the power plants from enforcement by the TCEQ. To remedy these violations with the EPA, both power plants retired SO2 emission allowances equivalent to their historic applicable emissions after expiration of the exemption in July of 2010. In addition, the EPA required payment of excess emission fees of $146,966 and $127,767 for Clear Lake and Texas City, respectively, which were remitted to the EPA in July of 2010. Accordingly, we now consider this matter closed.

Remediation of Certain Assets Acquired from Conectiv — As part of the Conectiv Acquisition on July 1, 2010, we assumed environmental remediation liabilities related to certain of the assets located in New Jersey that are subject to the Industrial Site Recovery Act and could incur expenditures related thereto of up to $10 million. Pursuant to the Conectiv Purchase Agreement, PHI is responsible for any amounts that exceed $10 million. We have engaged a licensed site remediation professional who is evaluating the recognized environmental conditions as a preliminary step of the site investigation phase and ultimate cleanup plan.

Heat Input Issues at Certain Assets Acquired from Conectiv — In 2010, prior to the Conectiv Acquisition, Conectiv received Title V air permits for its Cumberland 1 and Sherman Avenue peaker power plants from the NJDEP. These permits include heat input limits that may restrict operation at full capacity and are the subject of ongoing litigation between Conectiv and the NJDEP prompted by two Administrative Orders and Notices of Civil Administrative Penalty Assessment issued to Conectiv by the NJDEP. PHI asserts that the NJDEP does not have the authority to limit heat input in Title V air permits. We have submitted timely appeals of the Sherman Avenue and Cumberland 1 Title V air permits and continue to work with the NJDEP to ensure that all of the Conectiv New Jersey assets may operate at full load. Currently, these restrictions require one of our peaker power plants (Deepwater Unit 1) to operate at approximately 8 MW less than its full capacity. We are preparing an application to modify the Deepwater Unit 1 permit to reclaim the 8 MW limitation, but there can be no assurance that our application will be successful and we may continue to be subject to the aforementioned limitation.

Other Contingencies

Lyondell Bankruptcy — On January 6, 2009, Lyondell, including its subsidiary Houston Refining LP, filed for protection under Chapter 11 in the U.S. Bankruptcy Court. Channel Energy Center leases its project site from Houston Refining LP and is granted certain easements in, over, under and on the site pursuant to the lease. Channel Energy Center provides power and steam to Houston Refining LP pursuant to a power services agreement and, pursuant to a power plant services agreement, provides clarified water and treated water to Houston Refining LP. Channel Energy Center is provided with raw water, refinery gas and certain other power plant services by Houston Refining LP. On April 23, 2010, the U.S. Bankruptcy Court approved Lyondell’s plan of reorganization, which includes acceptance of the project site lease and power and plant services agreements described above. Additionally, we received approximately $13 million in settlement under Lyondell’s plan of reorganization to cure prepetition defaults under the assumed agreements during the second quarter of 2010. We reversed our bad debt allowance of approximately $10 million, which is reported as a component of sales, general and other administrative expense on our Consolidated Condensed Statement of Operations during the first quarter of 2010. We now consider this matter closed.

Distribution of Calpine Common Stock under our Plan of Reorganization — Through the filing of this Report, approximately 441 million shares have been distributed to holders of allowed unsecured claims and approximately 44 million shares remain in reserve for distribution to holders of disputed claims whose claims ultimately become allowed under our Plan of Reorganization. To the extent that any of the reserved shares remain undistributed upon resolution of the remaining disputed claims, such shares will not be returned to us but rather will be distributed pro rata to claimants with allowed claims to increase their recovery. We are not required to issue additional shares above the 485 million shares authorized to settle unsecured claims, even if the shares remaining for distribution are not sufficient to fully pay all allowed unsecured claims. However, certain disputed claims, including prepayment premium and default interest claims asserted by the holders of CalGen Third Lien Debt, may be required to be settled with available cash and cash equivalents to the extent reorganized Calpine Corporation common stock held in reserve pursuant to our Plan of Reorganization for such claims is insufficient in value to satisfy such claims in full. We consider such an outcome to be unlikely. To the extent that holders of the CalGen Third Lien Debt have claims that remain unsettled or outstanding, they assert that they continue to have lien rights to the assets of the CalGen entities until the pending claims asserted in the case styled:  HSBC Bank USA, NA as Indenture Trustee, et al v. Calpine Corporation, et al. Case No. 1: 07-cv-03088, S.D.N.Y. are resolved either through court action or settlement. We dispute such allegations and contend that all liens were released when the CalGen secured claims were paid in full under the terms of applicable court orders and our Plan of Reorganization as confirmed. We continue to engage in settlement discussions with the various constituencies in this dispute.