CALPINE CORP, 10-Q filed on 10/29/2010
Quarterly Report
Document and Company Information
9 Months Ended
Sep. 30, 2010
Oct. 26, 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
Q3 
 
Document Type
10-Q 
 
Document Period End Date
2010-09-30 
 
Amendment Flag
FALSE 
 
Entity Common Stock Shares Outstanding
 
444,530,340 
Consolidated Condensed Statements of Operations (Unaudited) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended
Sep. 30,
9 Months Ended
Sep. 30,
2010
2009
2010
2009
Consolidated Condensed Statements of Operations
 
 
 
 
Operating Revenues
$ 2,130 
$ 1,822 
$ 5,074 
$ 4,919 
Cost of revenue:
 
 
 
 
Fuel and purchased energy expense
1,143 
1,030 
3,016 
2,967 
Plant operating expense
199 
189 
630 
638 
Depreciation and amortization expense
149 
104 
414 
317 
Other cost of revenue
20 
19 
65 
62 
Total cost of revenue
1,511 
1,342 
4,125 
3,984 
Gross profit
619 
480 
949 
935 
Sales, general and other administrative expense
44 
38 
122 
131 
(Income) loss from unconsolidated investments in power plants
(1)
13 
(14)
(27)
Other operating expense
22 
29 
15 
Income from operations
554 
423 
812 
816 
Interest expense
314 
195 
722 
604 
Interest (income)
(2)
(3)
(8)
(13)
Debt extinguishment costs
20 
16 
27 
49 
Other (income) expense, net
Income before reorganization items, income taxes and discontinued operations
219 
211 
62 
170 
Reorganization items
 
(8)
 
(2)
Income before income taxes and discontinued operations
219 
219 
62 
172 
Income tax expense (benefit)
21 
(7)
38 
17 
Income before discontinued operations
198 
226 
24 
155 
Discontinued operations, net of tax expense
19 
11 
31 
34 
Net income
217 
237 
55 
189 
Net loss attributable to the noncontrolling interest
 
 
Net income attributable to Calpine
217 
238 
55 
192 
Basic earnings per common share attributable to Calpine:
 
 
 
 
Weighted average shares of common stock outstanding (in thousands) - basic
486,088 
485,736 
486,023 
485,619 
Income before discontinued operations - basic
0.41 
0.47 
0.05 
0.33 
Discontinued operations, net of tax expense - basic
0.04 
0.02 
0.06 
0.07 
Net income per common share - basic
0.45 
0.49 
0.11 
0.40 
Diluted earnings per common share attributable to Calpine:
 
 
 
 
Weighted average shares of common stock outstanding (in thousands) - diluted
487,443 
486,585 
487,199 
486,171 
Income before discontinued operations - diluted
0.41 
0.47 
0.05 
0.32 
Discontinued operations, net of tax expense - diluted
0.04 
0.02 
0.06 
0.07 
Net income per common share - diluted
$ 0.45 
$ 0.49 
$ 0.11 
$ 0.39 
Consolidated Condensed Balance Sheets (Unaudited) (USD $)
In Millions
Sep. 30, 2010
Dec. 31, 2009
Current assets:
 
 
Cash and cash equivalents ($437 and $242 attributable to VIEs. See Note 1)
$ 914 
$ 989 
Accounts receivable, net of allowance of $3 and $14
718 
750 
Margin deposits and other prepaid expense
253 
490 
Restricted cash, current ($265 and $322 attributable to VIEs. See Note 1)
296 
508 
Derivative assets, current
1,321 
1,119 
Assets held for sale ($545 attributable to VIEs. See Note 1)
545 
 
Inventory and other current assets
295 
243 
Total current assets
4,342 
4,099 
Property, plant and equipment, net ($6,744 and $5,319 attributable to VIEs. See Note 1)
12,915 
11,583 
Restricted cash, net of current portion ($40 and $45 attributable to VIEs. See Note 1)
45 
54 
Investments
69 
214 
Long-term derivative assets
318 
127 
Other assets non-current
693 
573 
Total assets
18,382 
16,650 
Current liabilities:
 
 
Accounts payable
523 
578 
Accrued interest payable
132 
54 
Debt, current portion ($552 and $106 attributable to VIEs. See Note 1)
574 
463 
Derivatives liabilities, current
1,247 
1,360 
Liabilities held for sale ($11 attributable to VIEs. See Note 1)
11 
 
Other current liabilities
299 
294 
Total current liabilities
2,786 
2,749 
Debt, net of current portion ($4,027 and $3,042 attributable to VIEs. See Note 1)
10,043 
8,996 
Deferred income taxes, net of current portion
159 
54 
Long-term derivative liabilities
499 
197 
Other long-term liabilities
275 
208 
Total liabilities
13,762 
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; 444,949,620 and 443,325,827 shares issued, respectively, and 444,501,702 and 442,998,255 shares outstanding, respectively
Treasury stock, at cost, 447,918 and 327,572 shares, respectively
(5)
(3)
Additional paid-in capital
12,275 
12,256 
Accumulated deficit
(7,485)
(7,540)
Accumulated other comprehensive loss
(166)
(266)
Total Calpine stockholders' equity
4,620 
4,448 
Noncontrolling interest
 
(2)
Total stockholders' equity
4,620 
4,446 
Total liabilties and stockholders' equity
$ 18,382 
$ 16,650 
Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $)
In Millions
9 Months Ended
Sep. 30,
2010
2009
Cash flows from operating activities:
 
 
Net income
$ 55 
$ 189 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization expense (1)
464 1
399 1
Debt extinguishment cost
27 
Deferred income taxes
40 
15 
Impairment loss
19 
 
Loss on disposal of assets
11 
29 
Unrealized mark-to-market activity, net
(97)
(67)
Income from unconsolidated investments in power plants
(14)
(27)
Return on investment in unconsolidated subsidiaries
11 
Stock-based compensation expense
18 
30 
Other operating activities
(3)
Change in operating assets and liabilities:
 
 
Accounts receivable
34 
(23)
Derivative instruments, net
(42)
(239)
Other assets
241 
387 
Accounts payable and accrued expenses
(1)
13 
Other liabilities
16 
(177)
Net cash provided by operating activities
783 
537 
Cash flows from investing activities:
 
 
Purchases of property, plant and equipment
(191)
(140)
Purchase of Connectiv assets
(1,634)
 
Cash acquired due to consolidation of OMEC
 
Contributions to unconsolidated investments
 
(19)
(Increase) decrease in restricted cash
228 
(2)
Other investing activities
(3)
Net cash used in investing activities
(1,585)
(164)
Cash flows from financing activities:
 
 
Repayments of project financing, notes payable and other
(472)
(1,339)
Borrowings from project financing, notes payable and other
1,272 
1,028 
Issuance of First Lien Notes
1,491 
 
Repayments on First Lien Credit Facility
(1,507)
(770)
Financing costs
(67)
(34)
Refund of financing costs
10 
 
Other financing activities
 
(2)
Net cash provided by (used in) financing activities
727 
(1,117)
Net decrease in cash and cash equivalents
(75)
(744)
Cash and cash equivalents, beginning of period
989 
1,657 
Cash and cash equivalents, end of period
914 
913 
Cash paid during the period for:
 
 
Interest, net of amounts capitalized
488 
563 
Income taxes
11 
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
(5)
Purchase of Connectiv assets included in accounts payable
 
Balance Sheet Parentheticals (Unaudited) (USD $)
In Millions, except Share data
Sep. 30, 2010
Dec. 31, 2009
Balance Sheet (Parentheticals)
 
 
Cash and cash equivalents attributable to VIE
$ 437 
$ 242 
Accounts Receivable, allowance for doubtful accounts
14 
Restricted cash, current attributable to VIE
265 
322 
Assets held for sale attributtable to VIE
545 
 
Property, plant and equipment, net attributable to VIE
6,744 
5,319 
Restricted cash, net of current portion attributable to VIE
40 
45 
Debt, current portion attributable to VIE
552 
106 
Liabilities held for sale attributable to VIE
11 
 
Debt, net of current portion attributable to VIE
4,027 
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
444,949,620 
443,325,827 
Common Stock, outstanding shares
444,501,702 
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, ERCOT and Eastern PJM. 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 U.S. GAAP have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 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 commodity and interest rate derivative contracts.

Consolidation of OMEC — We were required by U.S. 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 U.S. 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 property, plant and equipment, net, $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 nine months ended September 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 nine months ended September 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 U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.

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 September 30, 2010, and December 31, 2009, we had cash and cash equivalents of $304 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 September 30, 2010, and December 31, 2009 (in millions):

   
September 30, 2010
  
December 31, 2009
 
   
Current
  
Non-Current
  
Total
  
Current
  
Non-Current
  
Total
 
Debt service
 $48  $24  $72  $193  $25  $218 
Rent reserve
  23   5   28   34      34 
Construction/major maintenance
  89   9   98   87   22   109 
Security/project/insurance
  120      120   146      146 
Other
  16   7   23   48   7   55 
Total
 $296  $45  $341  $508  $54  $562 

Inventory — At September 30, 2010, and December 31, 2009, we had inventory of $260 million and $209 million, respectively. Inventory primarily consists of spare parts, stored natural gas and other fuel, 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 nine months ended September 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 third 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 nine months ended September 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.
Acquisitions and Planned Divesture
Acquisitions and Divestitures
2.   Acquisitions and Planned Divestitures

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 in excess of $10 million related to assets located in New Jersey that are subject to ISRA, or pre-close accumulated pension and retirement welfare liabilities; however, we did assume pension liabilities on future services and compensation increases for past services for approximately 128 union employees acquired in the Conectiv Acquisition of less than $10 million on the acquisition date. Our purchase price was approximately $1.64 billion. The net proceeds of $1.3 billion received from the NDH Project Debt were used, together with available cash, to pay the Conectiv Acquisition purchase price of approximately $1.64 billion and also fund a cash contribution from Calpine Corporation to NDH of $110 million to fund completion of the York Energy Center. See Note 6 for further discussion of the NDH Project Debt.

The Conectiv Acquisition provided us with a significant presence in the Eastern PJM market, one of the most robust competitive power markets in the U.S., and positioned 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 U.S. GAAP. During the three and nine months ended September 30, 2010, we expensed transaction and acquisition-related costs of approximately $6 million and approximately $25 million, respectively, of which, $5 million and $24 million, respectively, were included in sales, general and other administrative expense, and $1 million was included in plant operating expense on our Consolidated Condensed Statements of Operations.

The following table summarizes the consideration transferred for the Conectiv Acquisition and the preliminary values we assigned to the net assets acquired (in millions). The amounts below include revisions to the unrecorded and preliminary appraised values as presented in our June 30, 2010 Form 10-Q. Our preliminary values assigned below are still subject to finalization of working capital and other adjustments to the purchase price and finalization of the pension liability analysis and environmental site investigation/remediation reports. Our depreciation expense included for the three and nine months ended September 30, 2010, on the assets we obtained in the Conectiv Acquisition is based upon the preliminary values assigned below and represents our best estimate. Future changes, if any, to the values assigned could change our estimates of our depreciation expense in future periods; however, such changes, if any, are not expected to be material. We do not anticipate any significant goodwill will be recognized as a result of this acquisition.
 
Consideration
 
$
1,640
 
         
Preliminary values of identifiable assets acquired and liabilities assumed:
       
Assets:
       
Current assets
 
$
80
 
Property, plant and equipment, net
   
1,577
 
Other long-term assets
   
75
 
Total assets acquired
 
 
1,732
 
Liabilities:
       
Current liabilities
 
 
45
 
Long-term liabilities
   
47
 
Total liabilities assumed
   
92
 
Net assets acquired
 
$
1,640
 
 
During the three months ended September 30, 2010, the Conectiv Acquisition contributed $274 million in operating revenues and $91 million net income attributable to Calpine included in our Consolidated Condensed Statement of Operations.
 
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. 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 to our historical results for the periods indicated below (in millions, except per share amounts).

   
Three Months
    
   
Ended
  
Nine Months Ended September 30,
 
   
September 30, 2009
  
2010
  
2009
 
Operating revenues
 $2,403  $6,460  $6,544 
Net income (loss) attributable to Calpine
 $250  $(59) $132 
Basic earnings (loss) per common share attributable to Calpine
 $0.51  $(0.12) $0.27 
Diluted earnings (loss) per common share attributable to Calpine
 $0.51  $(0.12) $0.27 

Acquisition of Broad River and South Point

On September 23, 2010, we, through our wholly owned, indirect subsidiary, Calpine BRSP, entered into a purchase agreement with CIT Capital USA Inc., to purchase the equity interests related to our Broad River and South Point power plants for $320 million. We currently operate the Broad River power plant under a lease which did not qualify as a sale-leaseback transaction under U.S. GAAP, and the lease obligation is accounted for as debt in our project financing, notes payable and other debt balance, and we operate the South Point power plant under an operating lease, both with CIT Capital USA Inc. The purchase price consists of cash of approximately $38 million and assumed debt of approximately $282 million. However, the purchase of the equity interests is expected to only add an incremental $72 million in consolidated debt as the transaction will eliminate approximately $210 million in debt owed to CIT Capital USA Inc. by our Broad River power plant. This transaction requires FERC approval and is expected to close in the fourth quarter of 2010.

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. As of the filing of this Report, we have received all of the required approvals and we expect the sale to close in December 2010. The transaction is expected to remove the restrictions on approximately $86 million in restricted cash at closing. We expect to use the sales proceeds received and the approximately $86 million in restricted cash described above to repay project debt of approximately $418 million, 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 September 30, 2010. The results of operations of Blue Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Condensed Statements of Operations for the three and nine months ended September 30, 2010 and 2009.

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

   
September 30, 2010
 
Assets:
       
Current assets
 
$
14
 
Property, plant and equipment, net
   
513
 
Other long-term assets
   
18
 
Total assets held for sale
 
$
545
 
Liabilities:
       
Total liabilities held for sale, current
 
$
11
 

   
Three Months Ended September 30,
  
Nine Months Ended September 30,
 
   
2010
  
2009
  
2010
  
2009
 
Operating revenues
 $25  $25  $74  $76 
Income from discontinued operations before income taxes
 $17  $11  $37  $34 
Income tax expense (benefit)
  (2)     6    
Discontinued operations, net of tax expense
 $19  $11  $31  $34 

Sale of Partial Interest in Freestone

On October 27, 2010, we entered into an asset purchase and sale agreement to sell a 25% undivided interest in the assets of our Freestone power plant for approximately $215 million in cash at closing and will receive annual operating and energy management fees going forward. The sale is expected to close in the fourth quarter of 2010, but no later than the first quarter of 2011. We will continue to operate Freestone after the sale.
Property Plant and Equipment, Net
Property, Plant and Equipment, Net
3.  Property, Plant and Equipment, Net

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

   
September 30, 2010
   
December 31, 2009
 
Buildings, machinery and equipment
  $ 14,636     $ 13,373  
Geothermal properties
    1,089       1,050  
Other
    247       232  
      15,972       14,655  
Less: Accumulated depreciation
    3,590       3,322  
      12,382       11,333  
Land
    103       74  
Construction in progress
    430       176  
Property, plant and equipment, net
  $ 12,915     $ 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 nine months ended September 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 nine months ended September 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.

Impairment of Development Costs

During the three months ended September 30, 2010, we impaired development costs of approximately $19 million associated with a development project that originated prior to our Chapter 11 bankruptcy proceedings. We continued to market the project after our Effective Date; however, during the third quarter of 2010, we learned the project would not receive a PPA that would support its continued development and made the determination that continued development was unlikely. The expense is included in other operating expense on our Consolidated Condensed Statement of Operations and reflected in our Southeast segment.
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 subsidiaries 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 upon implementation and ongoing reassessments each reporting period 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. No further changes to our determinations of whether we are the primary beneficiary of our VIEs were required during the third quarter of 2010. 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 the 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 15,331 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. During the three and nine months ended September 30, 2010, Calpine Corporation provided $540 million to NDH, an indirect, wholly owned subsidiary, to fund the Conectiv Acquisition, including $110 million to complete the construction of the York Energy Center. Additionally, Calpine Corporation provided support in the form of other cash contributions other than amounts contractually required of approximately $8 million and $10 million during the three and nine months ended September 30, 2010, respectively.
 
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 (loss) from OMEC for the three and nine months ended September 30, 2009, and both Greenfield LP and Whitby for the three and nine months ended September 30, 2010 and 2009, are recorded in income from unconsolidated investments in power plants.

At September 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
September 30, 2010
  
September 30, 2010
  
Our Maximum Exposure to Loss at September 30, 2010(2)
  
December 31, 2009
 
OMEC(1)
  100%  $  $  $144 
Greenfield LP
  50%   68   68   70 
Whitby
  50%   1   1    
Total investments
     $69  $69  $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 September 30, 2010, and December 31, 2009, equity method investee debt was approximately $484 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 $242 million and $624 million as of September 30, 2010 and December 31, 2009, respectively.

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

   
Three Months Ended September 30,
  
Nine Months Ended September 30,
 
   
2010
  
2009
  
2010
  
2009
 
OMEC(1)
 $  $13  $  $(13)
Greenfield LP
     (1)  (7)  (11)
Whitby
  (1)  1   (7)  (3)
Total
 $(1) $13  $(14) $(27)
__________
 
(1)
OMEC was consolidated effective January 1, 2010. See Note 1. During the three and nine months ended September 30, 2009, we contributed $11 million and $19 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%. We received $6 million in distributions from Greenfield LP during the three and nine months ended September 30, 2010.

Whitby — Represents our 50% equity interest in Whitby held by our Canadian subsidiaries. We received $3 million and $5 million during the three and nine months ended September 30, 2010, respectively, and $2 million during the nine months ended September 30, 2009, in distributions from Whitby. We did not receive any distributions from Whitby during the three months ended September 30, 2009.

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 plant 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 including operations and maintenance.
Comprehensive Income (Loss)
Comprehensive Income (Loss)
5.  Comprehensive Income (Loss)

Comprehensive income (loss) includes our net income, 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 September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
Net income
  $ 217     $ 237     $ 55     $ 189  
Other comprehensive income (loss):
                               
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income
    65       (154 )     95       156  
Reclassification adjustment for cash flow hedges realized in net income
    (12 )     (108 )     10       (293 )
Foreign currency translation gain
          2             3  
Income tax benefit (expense)(1)
    4       15       (5 )     42  
Comprehensive income (loss)
    274       (8 )     155       97  
Add:  Comprehensive loss attributable to the noncontrolling interest
          1             3  
Comprehensive income (loss) attributable to Calpine
  $ 274     $ (7 )   $ 155     $ 100  
__________
 
(1)
Primarily due to intraperiod tax allocations.
Debt
Debt
6.  Debt

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

   
September 30, 2010
   
December 31, 2009
 
First Lien Credit Facility(1)
  $ 3,153     $ 4,661  
First Lien Notes
    2,691       1,200  
NDH Project Debt
    1,270        
Commodity Collateral Revolver(2)
          100  
Project financing, notes payable and other
    2,290       2,289  
CCFC Notes
    964       959  
Capital lease obligations
    249       250  
Total debt
    10,617       9,459  
Less: Current maturities
    574       463  
Debt, net of current portion
  $ 10,043     $ 8,996  
__________
 
(1)
On October 22, 2010, we issued $2.0 billion of 2021 First Lien Notes and repaid approximately $2.0 billion of the First Lien Credit Facility term loans.
 
(2)
The Commodity Collateral Revolver was repaid on July 8, 2010.
 
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 September 30, 2010, under our First Lien Credit Facility, we had approximately $3.2 billion outstanding under the term loans and $260 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 the First Lien Note offerings and repayments from excess cash flows. The First Lien Credit Facility matures on March 29, 2014. During 2010 we made significant repayments of our First Lien Credit Facility term loans through proceeds received from the issuances of the First Lien Notes of the following amounts:
 
 
In May 2010, we repaid approximately $394 million from the issuance of the 2019 First Lien Notes.
 
In July 2010, we repaid approximately $1.1 billion from the issuance of the 2020 First Lien Notes.
 
In October 2010, we repaid approximately $2.0 billion from the issuance of the 2021 First Lien Notes.

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.

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. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes. During 2010, we issued three tranches of First Lien Notes as further discussed below. We recorded deferred financing costs of approximately $26 million on our Consolidated Condensed Balance Sheet at September 30, 2010 and we recorded approximately $20 million and approximately $27 million in debt extinguishment costs for the three and nine months ended September 30, 2010, respectively, from the write-off of unamortized deferred financing costs related to the issuances of the First Lien Notes and the repayment of the First Lien Credit Facility term loans.

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 who are a 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.

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 indenture, dated as of July 23, 2010, among Calpine, the guarantors who are a 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.

Issuance of 2021 First Lien Notes — On October 22, 2010, we issued $2.0 billion in aggregate principal amount of 7.50% senior secured notes due 2021 in a private placement. The 2021 First Lien Notes were issued under an indenture, dated as of October 22, 2010, among Calpine, the guarantors who are a party thereto and Wilmington Trust Company, as trustee. The 2021 First Lien Notes bear interest at 7.50% payable semi-annually on February 15 and August 15 of each year beginning on February 15, 2011. Interest is due to the holders of record on February 1 and August 1 immediately preceding the applicable interest payment date. The 2021 First Lien Notes will mature on February 15, 2021. Proceeds received from the issuance of the 2021 First Lien Notes were used to repay approximately $2.0 billion of the First Lien Credit Facility term loans on October 22, 2010, and pay fees and expenses in connection with the offering of the 2021 First Lien Notes and such repayment. Additionally, we expect to record additional deferred financing costs of approximately $33 million and approximately $34 million in debt extinguishment costs from the write-off of unamortized deferred financing costs related to the issuance of the 2021 First Lien Notes during the fourth quarter of 2010.

NDH Project Debt — On June 8, 2010, NDH entered into a credit agreement, and we received net proceeds of $1.3 billion on July 1, 2010, which were used, together with available cash, to pay the Conectiv Acquisition purchase price of approximately $1.64 billion and also fund a cash contribution from Calpine Corporation to NDH of $110 million to fund completion of the York Energy Center. 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. 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. The NDH Project Debt also required that we enter into interest rate swap agreements to fix the variable LIBOR portion of our interest rate for a minimum of 50% of our debt. We executed three interest rate swap transactions in August 2010 with an initial aggregate notional amount of $715 million at a fixed LIBOR rate of 1.8275%.

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., an indirect, wholly owned subsidiary of Calpine Corporation, which purchases the power generated by NDH under an intercompany tolling agreement, which is 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 September 30, 2010, OMEC had approximately $367 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%.

Calpine BRSP DebtAs further discussed in Note 2, we expect to assume debt of approximately $282 million upon closing the purchase of the equity interests of our Broad River and South Point power plants. However, the purchase of the equity interests is expected to only add an incremental $72 million in consolidated debt as the transaction will eliminate approximately $210 million in debt owed to CIT Capital USA Inc. by our Broad River power plant. This transaction is expected to close in the fourth quarter of 2010.

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

   
September 30, 2010
   
December 31, 2009
 
First Lien Credit Facility
  $ 260     $ 206  
Calpine Development Holdings, Inc.(1)
    160       116  
NDH Credit Facility
    35        
Various project financing facilities
    109       90  
Total
  $ 564     $ 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 U.S. 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 September 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 September 30, 2010, and December 31, 2009 (in millions):

   
September 30, 2010
   
December 31, 2009
 
   
Fair Value
   
Carrying Value
   
Fair Value
   
Carrying Value
 
First Lien Credit Facility
  $ 3,079     $ 3,153     $ 4,402     $ 4,661  
First Lien Notes
    2,776       2,691       1,138       1,200  
NDH Project Debt
    1,316       1,270              
Commodity Collateral Revolver(1)
                94       100  
Project financing, notes payable and other(2)
    1,812       1,866       1,808       1,840  
CCFC Notes
    1,067       964       1,030       959  
Total
  $ 10,050     $ 9,944     $ 8,472     $ 8,760  
 _________
 
(1)
The Commodity Collateral Revolver was repaid on July 8, 2010.
 
(2)
Excludes leases that are accounted for as failed sale-leaseback transactions under U.S. GAAP and included in our project financing, notes payable and other balance.
 
Interest Expense
 
During the three and nine months ended September 30, 2010, $70 million in unrealized losses was reclassified out of AOCI and into our net income as interest expense for interest rate swaps that no longer qualified as cash flow hedges as the variable rate debt it was hedging was repaid with the proceeds received from the issuance of the 2020 First Lien Notes. Additionally, we expect an additional $130 million to $140 million in unrealized losses recorded in AOCI as of September 30, 2010, will be reclassified out of AOCI and into our net income as interest expense during the fourth quarter of 2010. These interest rate swaps were hedging the variable interest rates on approximately $2.0 billion of First Lien Credit Facility term loans that were repaid with the proceeds received from the issuance of the 2021 First Lien Notes on October 22, 2010, and will no longer qualify for cash flow hedges. Prospective changes in the fair value of these interest rate swaps will also be recorded in our net income as interest expense instead of AOCI and may create variability in our interest expense in future periods.
Fair Value Measurements
Fair Value Measurements
7.  Fair Value Measurements

Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and in restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Our cash equivalents are classified within level 1 of the fair value hierarchy.
 
Margin Deposits and Margin Deposits Held by Us Posted by Our Counterparties — Margin deposits and margin deposits held by us posted by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits held by us posted by our counterparties are generally cash and cash equivalents and are classified within level 1 of the fair value hierarchy.

Derivatives — The primary factors affecting the fair value of our 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.

The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 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 September 30, 2010
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
   
(in millions)
 
Assets:
                       
Cash equivalents(1)
  $ 989     $     $     $ 989  
Margin deposits
    178                   178  
Commodity instruments:
                               
Commodity futures contracts
    1,142                   1,142  
Commodity forward contracts(2)
          415       81       496  
Interest rate swaps
          1             1  
Total assets
  $ 2,309     $ 416     $ 81     $ 2,806  
                                 
Liabilities:
                               
Margin deposits held by us posted by our counterparties
  $ 62     $     $     $ 62  
Commodity instruments:
                               
Commodity futures contracts
    1,097                   1,097  
Commodity forward contracts(2)
          174       17       191  
Interest rate swaps
          458             458  
Total liabilities
  $ 1,159     $ 632     $ 17     $ 1,808  

   
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
    413                   413  
Commodity instruments:
                               
Commodity futures contracts
    953                   953  
Commodity forward contracts(2)
          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
  $ 9     $     $     $ 9  
Commodity instruments:
                               
Commodity futures contracts
    1,096                   1,096  
Commodity forward contracts(2)
          91       33       124  
Interest rate swaps
          337             337  
Total liabilities
  $ 1,105     $ 428     $ 33     $ 1,566  
__________
 
(1)
As of September 30, 2010, and December 31, 2009, we had cash equivalents of $695 million and $770 million included in cash and cash equivalents and $294 million and $536 million included in restricted cash, respectively.
 
(2)
Includes OTC swaps and options.

The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):

   
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
   
2010
 
2009
 
2010
 
2009
 
Balance, beginning of period
 
$
43
 
$
91
 
$
38
 
$
105
 
Realized and unrealized gains (losses):
                         
Included in net income:
                         
Included in operating revenues(1)
   
12
   
(4
)
 
31
   
(1
)
Included in fuel and purchased energy expense(2)
   
2
   
(1
)
 
(1
)
 
6
 
Included in OCI
   
4
   
1
   
6
   
13
 
Purchases, issuances, sales and settlements:
                         
Settlements
   
(2
)
 
(8
)
 
(13
)
 
(34
)
Transfers into and/or out of level 3(3):
                         
Transfers into level 3(4)
   
1
   
   
   
(5
)
Transfers out of level 3(5)
   
4
   
(18
)
 
3
   
(23
)
Balance, end of period
 
$
64
 
$
61
 
$
64
 
$
61
 
                           
Change in unrealized gains and (losses) relating to instruments still held at end of period
 
$
14
 
$
(5
)
$
30
 
$
5
 
__________
 
(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 nine months ended September 30, 2010 and 2009.
 
(4)
We had $1 million in gains transferred into level 3 out of level 2 for the three months ended September 30, 2010, due to changes in market liquidity in various power markets. There were no significant transfers into level 3 out of level 2 for the three months ended September 30, 2009, and the nine months ended September 30, 2010. We had $5 million in losses transferred into level 3 out of level 2 for the nine months ended September 30, 2009, due to changes in market liquidity in various power markets.
 
(5)
We had $4 million in losses and $18 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2010 and 2009, respectively. We had $3 million in losses and $23 million in gains transferred out of level 3 into level 2 for the nine months ended September 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 September 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 2 and 16 years, respectively.

As of September 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
   
September 30, 2010
 
December 31, 2009
   
Power (MWh)
   
(43
)
   
(52
)
Natural gas (MMBtu)
   
5
     
78
 
Interest rate swaps
 
$
6,579
   
$
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 any additional collateral posted as a result of a one credit rating level downgrade would be material. The aggregate fair value of our derivative liabilities with credit-contingent provisions as of September 30, 2010, was $9 million for which we have posted collateral of $2 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 U.S. 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 September 30, 2010, and December 31, 2009 (in millions):

   
September 30, 2010
 
               
Total
 
Balance Sheet Presentation
 
Interest Rate
   
Commodity
   
Derivative
 
 
Swaps
   
Instruments
   
Instruments
 
Current derivative assets
  $     $ 1,321     $ 1,321  
Long-term derivative assets
    1       317       318  
Total derivative assets
  $ 1     $ 1,638     $ 1,639  
                         
Current derivative liabilities
  $ 201     $ 1,046     $ 1,247  
Long-term derivative liabilities
    257       242       499  
Total derivative liabilities
  $ 458     $ 1,288     $ 1,746  
Net derivative assets (liabilities)
  $ (457 )   $ 350     $ (107 )

   
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 )

   
September 30, 2010
 
   
Fair Value
   
Fair Value
 
   
of Derivative
   
of Derivative
 
   
Assets
   
Liabilities
 
Derivatives designated as cash flow hedging instruments:
           
Interest rate swaps
  $ 1     $ 311  
Commodity instruments
    305       81  
Total derivatives designated as cash flow hedging instruments
  $ 306     $ 392  
                 
Derivatives not designated as hedging instruments:
               
Interest rate swaps
  $     $ 147  
Commodity instruments
    1,333       1,207  
Total derivatives not designated as hedging instruments
  $ 1,333     $ 1,354  
Total derivatives
  $ 1,639     $ 1,746  

   
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
 


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 income.

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 September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
Realized gain (loss)
                       
Interest rate swaps
  $ (14 )   $ (3 )   $ (26 )   $ (12 )
Commodity instruments
    41       1       93       (13 )
Total realized gain (loss)
  $ 27     $ (2 )   $ 67     $ (25 )
                                 
Unrealized gain (loss) (1)
                               
Interest rate swaps
  $ (96 )   $ 1     $ (115 )   $ 5  
Commodity instruments
    131       43       212       60  
Total unrealized gain
  $ 35     $ 44     $ 97     $ 65  
Total mark-to-market activity
  $ 62     $ 42     $ 164     $ 40  
__________
 
(1)
Changes in unrealized gains and losses include hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
Realized and unrealized gain (loss)
                       
Power contracts included in operating revenues
  $ 22     $ 17     $ 34     $ 8  
Natural gas contracts included in fuel and purchased energy expense
    150       27       271       39  
Interest rate swaps included in interest expense
    (110 )     (2 )     (141 )     (7 )
Total mark-to-market activity
  $ 62     $ 42     $ 164     $ 40  

Derivatives Included in OCI and AOCI

The following tables detail the effect of our net derivative instruments that qualify for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):
 
   
Three Months Ended September 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
 
$
45
 
$
(17
$
(50
)(1)
$
(60
)(1)   
$
(1)
$
 
Commodity instruments
   
8
   
(245
)
 
62
(2) 
 
168
(2)   
 
(1
)(2)
 
 
Total
 
$
53
 
$
(262
)
$
12
 
$
108
 
$
(1
)
$
 

   
Nine Months Ended September 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
 
$
18
 
$
70
 
$
(172
)(1)
$
(152
)(1)   
$
(1)
$
 
Commodity instruments
   
87
   
(207
)
 
162
(2) 
 
445
(2)   
 
(2)
 
 
Total
 
$
105
 
$
(137
)
$
(10
)
$
293
 
$
 
$
 
__________
 
(1)
Included in interest expense on our Consolidated Condensed Statements of Operations. During the three months ended September 30, 2010, an additional $70 million in unrealized losses was reclassified out of AOCI for interest rate swaps that no longer qualified as cash flow hedges as the variable rate debt it was hedging was repaid with the proceeds received from the issuance of the 2020 First Lien Notes. The corresponding amounts were reclassified into our net income as additional interest expense.
 
(2)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

Assuming constant September 30, 2010, power and natural gas prices and interest rates, we estimate that pre-tax net gains of $33 million would be reclassified from AOCI into our net income 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 our net income (positive or negative) will be for the next 12 months. Additionally, as of September 30, 2010, approximately $130 million to $140 million in unrealized losses were recorded in AOCI for interest rate swaps that were hedging the variable interest rates on approximately $2.0 billion of First Lien Credit Facility term loans, which were repaid (see Note 6 for further discussion of our issuance of the 2021 First Lien Notes). These interest rate swaps will no longer qualify as cash flow hedges and the corresponding amounts will be reclassified into our net income during the fourth quarter of 2010 as additional interest expense. Additionally, prospective changes in the fair value of these interest rate swaps will also be recorded in our net income 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 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 September 30, 2010, and December 31, 2009 (in millions):

   
September 30, 2010
  
December 31, 2009
 
Margin deposits(1)
 $178  $413 
Natural gas and power prepayments
  32   34 
Total margin deposits and natural gas and power prepayments with our counterparties(2)
 $210  $447 
          
Letters of credit issued
 $455  $353 
First priority liens under power and natural gas agreements(3)
      
First priority liens under interest rate swap agreements
  428   333 
Total letters of credit and first priority liens with our counterparties
 $883  $686 
          
Margin deposits held by us posted by our counterparties(1)(4)
 $62  $9 
Letters of credit posted with us by our counterparties
  111   70 
Total margin deposits and letters of credit posted with us by our counterparties
 $173  $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 September 30, 2010, and December 31, 2009, $187 million and $426 million were included in margin deposits and other prepaid expense, respectively, and $23 million and $21 million were included in other assets at September 30, 2010 and December 31, 2009, respectively, on our Consolidated Condensed Balance Sheets.
 
(3)
At September 30, 2010, and December 31, 2009, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $275 million and $123 million, respectively; therefore, there was no collateral exposure at September 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 U.S. 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 September 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 nine months ended September 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.

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding non-controlling interest), and our imputed tax rates, as well as intraperiod tax allocations, with partially offsetting tax expense (benefit) allocated between discontinued operations or OCI, for the periods indicated (in millions):
 
   
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
   
2010
 
2009
 
2010
 
2009
 
Income tax expense (benefit)
 
$
21
 
$
(7
)
$
38
(1)
$
17
 
Imputed tax rate
   
10
%
 
(3
)%
 
61
%
 
10
%
Intraperiod tax allocation expense (benefit)
 
$
43
 
$
15
 
$
(27
)(1)
$
42
 
__________
 
(1)
Includes approximately $13 million in tax expense related to a prior period.

Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. 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 September 30, 2010, we had unrecognized tax benefits of $87 million. If recognized, $41 million of our unrecognized tax benefits could impact the annual effective tax rate and $46 million related to deferred tax assets could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $19 million for income tax matters as of September 30, 2010. The amount of unrecognized tax benefits decreased by $11 million for the nine months ended September 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 is 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 and the CCFC group adjusted their NOLs for prior periods through December 31, 2009, increasing it by approximately $150 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, a $33 million decrease for return to provision adjustments and other increases of $2 million; however, because of the Calpine group's valuation allowance on its NOL, there is no impact on our income tax expense.

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.
Earnings Per Share
Earnings Per Share
11.  Earnings 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.

Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2010 and 2009, are:

   
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
   
2010
 
2009
 
2010
 
2009
 
   
(shares in thousands)
 
Diluted weighted average shares calculation:
                         
Weighted average shares outstanding (basic)
   
486,088
   
485,736
   
486,023
   
485,619
 
Share-based awards
   
1,355
   
849
   
1,176
   
552
 
Weighted average shares outstanding (diluted)
   
487,443
   
486,585
   
487,199
   
486,171
 

We excluded the following potentially dilutive securities from our calculation of weighted average shares outstanding from diluted earnings per common share for the periods indicated:

   
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
   
2010
 
2009
 
2010
 
2009
 
   
(shares in thousands)
 
Share-based awards
   
14,625
   
13,203
   
14,193
   
13,115
 
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 Director Plan and Equity Plan, 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 nine months ended September 30, 2010 and 2009.

On August 11, 2010, we awarded stock options to purchase an aggregate of 3,260,000 shares of our common stock to certain executive officers under the Equity Plan. These stock options provide a generally competitive compensation opportunity for the current or a similar economic environment, but contain a market condition to reduce in number as, and if, our common stock prices return to historical pricing levels. Specifically, if on the date of exercise of the stock options, the closing price of our common stock exceeds the exercise price plus 25% ($15.80), then the number of shares underlying the stock options that may be exercised on that date of exercise shall be reduced, on a straight-line basis, beginning when the closing price on the date of exercise exceeds $15.80 and ending when such closing price equals or exceeds $27.50 per share at which price the number of shares underlying the stock options shall be reduced to zero shares. The stock options contain a cliff vesting term of approximately three years and expiration coincides with the expiration of each executive officer’s respective employment inducement options, or expires upon a termination of employment. Due to the market condition contained in the option agreements (described above), these options are valued using the Monte Carlo simulation model.

We use the Black-Scholes option-pricing model or the Monte Carlo simulation 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 $8 million for the three months ended September 30, 2010 and 2009, respectively, and $18 million and $30 million for the nine months ended September 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 nine months ended September 30, 2010 and 2009. At September 30, 2010, there was unrecognized compensation cost of $22 million related to options, $15 million related to restricted stock and nil related to restricted stock units, which is expected to be recognized over a weighted average period of 2.1 years for options, 1.9 years for restricted stock and 0.6 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 nine months ended September 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
4,311,791
 
$
12.31
           
Exercised
810
 
$
8.84
           
Forfeited
290,209
 
$
12.36
           
Expired
255,010
 
$
17.43
           
Outstanding – September 30, 2010
16,998,281
 
$
17.51
 
5.8
 
$
4
 
Exercisable – September 30, 2010
6,247,624
 
$
19.28
 
6.0
 
$
 
Vested and expected to vest – September 30, 2010
16,663,135
 
$
17.63
 
5.7
 
$
4
 

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

The fair value of options granted during the nine months ended September 30, 2010 and 2009, was determined on the grant date using the Black-Scholes pricing model or the Monte Carlo simulation model, as appropriate. 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)
    4.0 – 6.5       6.0 – 6.5  
Risk-free interest rate(2)
    1.3 – 3.3 %     2.3 – 2.9 %
Expected volatility(3)
    34.1 – 37.6 %     60.1 – 73.0 %
Dividend yield(4)
           
Weighted average grant-date fair value (per option)
  $ 1.80     $ 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 nine months ended September 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
 
$
11.31
 
Forfeited
294,314
 
$
10.87
 
Vested
438,534
 
$
15.49
 
Nonvested – September 30, 2010
2,788,161
 
$
11.18
 

The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2010 and 2009, was $4 million and $8 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 September 30, 2010, our reportable segments were West (including geothermal), Texas, North (including Canada) and Southeast. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.

Commodity Margin 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. Our North segment information for the three and nine months ended September 30, 2010, also includes the financial results of the assets we acquired from Conectiv beginning on the acquisition date of July 1, 2010, with no similar revenues and expenses included for the three and nine months ended September 30, 2009. See Note 2 for further discussion of our discontinued operations and our Conectiv Acquisition.

   
Three Months Ended September 30, 2010
 
                           
Consolidation
       
                           
and
       
   
West
   
Texas
   
North
   
Southeast
   
Elimination
   
Total
 
Revenues from external customers
  $ 716     $ 670     $ 468     $ 276     $     $ 2,130  
Intersegment revenues
    2       6       2       53       (63 )      
Total operating revenues
  $ 718     $ 676     $ 470     $ 329     $ (63 )   $ 2,130  
Commodity Margin
  $ 338     $ 165     $ 259     $ 90     $     $ 852  
Add: Mark-to-market commodity activity, net and other revenue(1)
    42       62       18       18       (6 )     134  
Less:
                                               
Plant operating expense
    86       55       38       28       (8 )     199  
Depreciation and amortization expense
    50       36       37       28       (2 )     149  
Other cost of revenue(2)
    12             5             2       19  
Gross profit
    232       136       197       52       2       619  
Other operating expenses
    14       14       12       24       1       65  
Income from operations
    218       122       185       28       1       554  
Interest expense, net of interest income
                                            312  
Debt extinguishment costs and other (income) expense, net
                                            23  
Income before income taxes and discontinued operations
                                          $ 219  



   
Three Months Ended September 30, 2009
 
                           
Consolidation
       
                           
and
       
   
West
   
Texas
   
North
   
Southeast
   
Elimination
   
Total
 
Revenues from external customers
  $ 887     $ 530     $ 167     $ 238     $     $ 1,822  
Intersegment revenues
    5       6             24       (35 )      
Total operating revenues
  $ 892     $ 536     $ 167     $ 262     $ (35 )   $ 1,822  
Commodity Margin
  $ 368     $ 187     $ 96     $ 92     $     $ 743  
Add: Mark-to-market commodity activity, net and other revenue(1)
    41       2       21       (4 )     (12 )     48  
Less:
                                               
Plant operating expense
    92       35       18       27       17       189  
Depreciation and amortization expense
    45       27       16       17       (1 )     104  
Other cost of revenue(2)
    17       6       10       3       (18 )     18  
Gross profit
    255       121       73       41       (10 )     480  
Other operating expenses
    32       14       3       8             57  
Income from operations
    223       107       70       33       (10 )     423  
Interest expense, net of interest income
                                            192  
Debt extinguishment costs and other (income) expense, net
                                            20  
Income before reorganization items, income taxes and discontinued operations
                                            211  
Reorganization items
                                            (8 )
Income before income taxes and discontinued operations
                                          $ 219  


   
Nine Months Ended September 30, 2010
 
                           
Consolidation
       
                           
and
       
   
West
   
Texas
   
North
   
Southeast
   
Elimination
   
Total
 
Revenues from external customers
  $ 1,906     $ 1,749     $ 725     $ 694     $     $ 5,074  
Intersegment revenues
    7       16       4       97       (124 )      
Total operating revenues
  $ 1,913     $ 1,765     $ 729     $ 791     $ (124 )   $ 5,074  
Commodity Margin
  $ 809     $ 400     $ 390     $ 216     $     $ 1,815  
Add: Mark-to-market commodity activity, net and other revenue(1)
    60       148       18       31       (20 )     237  
Less:
                                               
Plant operating expense
    264       217       83       87       (21 )     630  
Depreciation and amortization expense
    151       110       75       83       (5 )     414  
Other cost of revenue(2)
    37       1       19       2             59  
Gross profit
    417       220       231       75       6       949  
Other operating expenses
    46       33       26       31       1       137  
Income from operations
    371       187       205       44       5       812  
Interest expense, net of interest income
                                            714  
Debt extinguishment costs and other (income) expense, net
                                            36  
Income before income taxes and discontinued operations
                                          $ 62  



   
Nine Months Ended September 30, 2009
 
                           
Consolidation
       
                           
and
       
   
West
   
Texas
   
North
   
Southeast
   
Elimination
   
Total
 
Revenues from external customers
  $ 2,513     $ 1,386     $ 431     $ 589     $     $ 4,919  
Intersegment revenues
    22       59       13       79       (173 )      
Total operating revenues
  $ 2,535     $ 1,445     $ 444     $ 668     $ (173 )   $ 4,919  
Commodity Margin
  $ 918     $ 505     $ 215     $ 233     $     $ 1,871  
Add: Mark-to-market commodity activity, net and other revenue(1)
    120       (48 )     37       2       (35 )     76  
Less:
                                               
Plant operating expense
    310       163       61       94       10       638  
Depreciation and amortization expense
    137       88       47       50       (5 )     317  
Other cost of revenue(2)
    44       11       23       7       (28 )     57  
Gross profit
    547       195       121       84       (12 )     935  
Other operating expenses
    45       51             23             119  
Income from operations
    502       144       121       61       (12 )     816  
Interest expense, net of interest income
                                            591  
Debt extinguishment costs and other (income) expense, net
                                            55  
Income before reorganization items, income taxes and discontinued operations
                                            170  
Reorganization items
                                            (2 )
Income before income taxes and discontinued operations
                                          $ 172  
__________
 
(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 $1 million of RGGI compliance and other environmental costs for both the three months ended September 30, 2010 and 2009, and $6 million and $5 million for the nine months ended September 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 U.S. 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. On August 2, 2010, the Ninth Circuit ruled in favor of BLM and us, concluding that the BLM may properly reconsider its decision to extend the term of our two Four-Mile Hill leases. We understand that the Pit River Tribe has until November 1, 2010, to file a writ of certiorari to the U.S. Supreme Court.

In addition, in May 2004, 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. 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 have remained mostly inactive pending the outcome of the above described Pit River Tribe case. Now that the above Pit River Tribe case has been resolved, we anticipate the Pit River Tribe and other interested parties may seek to reactivate the two additional suits.

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:

Environmental 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 ISRA. We have accrued approximately $6 million in liabilities as of September 30, 2010, 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. Until our acquisition accounting is finalized for the Conectiv Acquisition, any future changes to our environmental remediation liabilities, if any, would not impact future earnings, but would be reflected in our allocation of the Conectiv Acquisition purchase price. See Note 2 for disclosures related to our Conectiv Acquisition. We have engaged a licensed site remediation professional who has evaluated the recognized environmental conditions and is conducting site investigations in accordance with ISRA requirements as a precursor to developing the ultimate cleanup plan.

Heat Input Limits at Deepwater Unit 1 — Prior to our acquisition, Conectiv was a party to certain pending penalty proceedings in the administrative courts of the State of New Jersey involving one of the older peaker power plants (Deepwater Unit 1). The NJDEP alleged that Deepwater Unit 1 had exceeded its permissible maximum heat input limit, which restricts the amount of fuel burned. Heat input limits are imposed on power plants without emissions monitoring equipment to limit emissions of pollutants that are not subject to measurement by continuous emissions monitoring systems. Appeals were filed in 2007, and a status hearing has been set for later this year. The appeals assert that the NJDEP does not have the authority to limit heat input in Title V air permits. We plan to continue to work with the NJDEP to ensure that our 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 of 86 MW. We are preparing an application to modify the Deepwater Unit 1 air permit to reclaim the 8 MW limitation, but there can be no assurance that our application will be successful.

Other Contingencies

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. Recently the district court in the above litigation issued a decision that the holders of the CalGen Third Lien Debt were not entitled, as a matter of law, to a prepayment premium or to attorney’s fees associated with the payoff of the underlying obligations. Further, the district court determined that the holders of the CalGen Third Lien Debt were only entitled to interest as specified in the supporting debt agreements, but did not rule on the issue of this entitlement to default interest on their claims. We believe the holders of the CalGen Third Lien Debt will file an appeal of the judgment entered by the district court. We continue to engage in settlement discussions with the various constituencies in this dispute.