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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(Unaudited)
1. Basis of Presentation and Summary of Significant Accounting Policies
We are an independent wholesale power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, 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 and fuel oil as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to economically hedge our business risks and optimize our portfolio of power plants.
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2010, included in our 2010 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.
Reclassifications — Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the three and six months ended June 30, 2010 to conform to the current period presentation. Our reclassifications are summarized as follows:
• | We have reclassified amounts attributable to interest rate swaps formerly hedging our First Lien Credit Facility term loans previously recorded in interest expense to (gain) loss on interest rate derivatives, net of approximately $(8) million and $3 million for the three and six months ended June 30, 2010, respectively. See Note 7 for further information about our interest rate swaps formerly hedging our First Lien Credit Facility. |
• | We have reclassified depreciation expense on corporate asse |
• | We have reclassified cash payments on our interest rate swaps formerly hedging our First Lien Credit Facility term loans previously included in net cash provided by operating activities of approximately $14 million to settlement of non-hedging interest rate swaps included in net cash provided by (used in) investing activities for the six months ended June 30, 2010. |
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At June 30, 2011, and December 31, 2010, we had cash and cash equivalents of $301 million and $269 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Consolidated Condensed Statements of Cash Flows. The table below represents the components of our restricted cash at June 30, 2011, and December 31, 2010 (in millions):
|
| June 30, 2011 |
|
| December 31, 2010 |
| ||||||||||||||||||||||||
|
| Current |
|
| Non-Current |
|
| Total |
|
| Current |
|
| Non-Current |
|
| Total |
| ||||||||||||
Debt service |
| $ | 48 |
|
| $ | 28 |
|
| $ | 76 |
|
| $ | 44 |
|
| $ | 25 |
|
| $ | 69 |
| ||||||
Rent reserve |
|
| 5 |
|
|
| — |
|
|
| 5 |
|
|
| 22 |
|
|
| 5 |
|
|
| 27 |
| ||||||
Construction/major maintenance |
|
| 56 |
|
|
| 3 |
|
|
| 59 |
|
|
| 35 |
|
|
| 14 |
|
|
| 49 |
| ||||||
Security/project/insurance |
|
| 51 |
|
|
| 7 |
|
|
| 58 |
|
|
| 75 |
|
|
| 7 |
|
|
| 82 |
| ||||||
Other |
|
| 15 |
|
|
| 4 |
|
|
| 19 |
|
|
| 19 |
|
|
| 2 |
|
|
| 21 |
| ||||||
Total |
| $ | 175 |
|
| $ | 42 |
|
| $ | 217 |
|
| $ | 195 |
|
| $ | 53 |
|
| $ | 248 |
|
Inventory — At June 30, 2011 and December 31, 2010, we had inventory of $246 million and $262 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost under the weighted average cost method or market value. Spare parts inventory is valued at the weighted average cost and are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Property, Plant and Equipment — At June 30, 2011 and December 31, 2010, the components of property, plant and equipment were stated at cost less accumulated depreciation as follows (in millions):
|
| June 30, |
|
| December 31, |
| ||||
Buildings, machinery and equipment |
| $ | 14,966 |
|
| $ | 14,578 |
| ||
Geothermal properties |
|
| 1,143 |
|
|
| 1,102 |
| ||
Other |
|
| 265 |
|
|
| 273 |
| ||
|
|
| 16,374 |
|
|
| 15,953 |
| ||
Less: Accumulated depreciation |
|
| 3,931 |
|
|
| 3,690 |
| ||
|
|
| 12,443 |
|
|
| 12,263 |
| ||
Land |
|
| 94 |
|
|
| 93 |
| ||
Construction in progress |
|
| 496 |
|
|
| 622 |
| ||
Property, plant and equipment, net |
| $ | 13,033 |
|
| $ | 12,978 |
|
Capitalized Interest — The total amount of interest capitalized was $4 million and $1 million for the three months ended June 30, 2011 and 2010, respectively, and $11 million and $2 million for the six months ended June 30, 2011 and 2010, respectively.
New Accounting Standards and Disclosure Requirements
Fair Value Measurement — In May 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-04, “Fair Value Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating to fair value measurements. The update stems from the Financial Accounting Standards Board and the International Accounting Standards Board project to develop common requirements for measuring fair value and for disclosing information about fair value measurements. The update is not expected to impact any of our fair value measurements but will require disclosure of the following:
• | quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy; |
• | for those fair value measurements categorized within level 3 of the fair value hierarchy, both the |
• | the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed. |
The new requirements relating to fair value measurements are prospective and effective for interim and annual periods beginning after December 15, 2011 with early adoption prohibited. We do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.
Comprehensive Income — In June 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-05, “Comprehensive Income” to amend requirements relating to the presentation of comprehensive income. The update eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders‘ equity and provides an entity with the option to present comprehensive income in a single continuous financial statement or in two separate but consecutive statements. The new requirements relating to the presentation of comprehensive income are retrospective and effective for interim and annual periods beginning after December 15, 2011 with early adoption permitted. We have not elected to early adopt the requirements related to the update at June 30, 2011. Since the update only requires a change in presentation, we do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.
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2. Acquisitions, Divestitures and Discontinued Operations
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 the York Energy Center that was under construction and achieved COD on March 2, 2011, totaling approximately 4,490 MW of capacity (including completion of the 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 129 union employees who joined Calpine as a result of the Conectiv Acquisition. The net proceeds of $1.3 billion received from the NDH Project Debt were used, together with available operating 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.
The Conectiv Acquisition provided us with a significant presence in the Mid-Atlantic market, one of the most robust competitive power markets in the U.S., and positioned us with three scale markets instead of two (California and Texas) 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 second quarter of 2011, we finalized the valuations we assigned to the net assets acquired in the Conectiv Acquisition which is summarized in the following table (in millions). We did not record any material valuation adjustments during the three and six months ended June 30, 2011, and we did not recognize any goodwill as a result of this acquisition.
|
|
|
| ||
Consideration |
| $ | 1,640 |
| |
|
|
|
|
| |
Final values of identifiable assets acquired and liabilities assumed: |
|
|
|
| |
Assets: |
|
|
|
| |
Current assets |
| $ | 78 |
| |
Property, plant and equipment, net |
|
| 1,574 |
| |
Other long-term assets |
|
| 85 |
| |
Total assets acquired |
|
| 1,737 |
| |
Liabilities: |
|
|
|
| |
Current liabilities |
|
| 46 |
| |
Long-term liabilities |
|
| 51 |
| |
Total liabilities assumed |
|
| 97 |
| |
Net assets acquired |
| $ | 1,640 |
|
Sale of Blue Spruce and Rocky Mountain
On December 6, 2010, we, through our indirect, wholly owned subsidiaries Riverside Energy Center, LLC and Calpine Development Holdings, Inc., completed the sale of 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, and we recorded a pre-tax gain of approximately $209 million during the fourth quarter of 2010. The results of operations for Blue Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Condensed Statement of Operations for the three and six months ended June 30, 2010.
The table below presents the components of our discontinued operations for the periods presented (in millions):
|
| Three Months Ended |
|
| Six Months Ended |
| ||||
|
| June 30, 2010 |
|
| June 30, 2010 |
| ||||
Operating revenues |
| $ | 25 |
|
| $ | 50 |
| ||
Income from discontinued operations before taxes |
| $ | 12 |
|
| $ | 20 |
| ||
Less: Income tax expense |
|
| 8 |
|
|
| 8 |
| ||
Discontinued operations, net of tax |
| $ | 4 |
|
| $ | 12 |
|
|
3. 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 consolidated in our financial statements:
Subsidiaries with Project Debt — All of our subsidiaries with project debt guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. 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 5 for further information regarding our project debt and Note 1 for information regarding our restricted cash balances.
Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our ownership and thus constitute a VIE.
VIEs with a Purchase Option — Riverside Energy Center and OMEC have agreements that provide third parties a fixed price option to purchase power plant assets with an aggregate capacity of 1,211 MW exercisable in the years 2013 and 2019. These purchase options limit the risk and reward of our ownership and, thus, constitute a VIE.
Consolidation of VIEs
We consolidate our VIEs where we determine that we have 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. We have determined 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 determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes 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, and 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 is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
• | perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and |
• | evaluate if an entity is a VIE and whether we are the primary beneficiary whenever 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. |
There were no changes to our determination of whether we are the primary beneficiary of our VIEs during the first half of 2011.
VIE Disclosures
U.S. GAAP also requires separate disclosure on the face of our Consolidated Condensed Balance Sheets 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. In determining which assets of our VIEs met the separate disclosure criteria, we determined this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where there are agreements that prohibit the VIE from guaranteeing the debt of Calpine Corporation or its other subsidiaries. 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 and where the amounts were material to our financial statements.
The VIEs meeting the above disclosure criteria are majority owned subsidiaries of Calpine Corporation and include natural gas-fired power plants with an aggregate capacity of approximately 11,064 MW and 13,553 MW at June 30, 2011 and December 31, 2010, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements between the VIEs, Calpine Corporation and its other wholly owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Calpine Corporation provided support to these VIEs in the form of cash and other contributions other than amounts contractually required of nil for both the three months ended June 30, 2011 and 2010, and $52 million and $1 million during the six months ended June 30, 2011 and 2010, respectively.
Unconsolidated VIEs and Investments
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Condensed Balance Sheets in accordance with U.S. GAAP. Our ownership interest in the net income for Greenfield LP and Whitby for the three and six months ended June 30, 2011 and 2010, are recorded in (income) loss from unconsolidated investments in power plants. At June 30, 2011 and December 31, 2010, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
|
| Ownership Interest as of June 30, 2011 |
|
| June 30, |
|
| December 31, |
| ||||||
Greenfield LP |
|
| 50 | % |
| $ | 79 |
|
| $ | 77 |
| |||
Whitby |
|
| 50 | % |
|
| 5 |
|
|
| 3 |
| |||
Total investments |
|
|
|
|
| $ | 84 |
|
| $ | 80 |
|
_________
(1) | 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. At June 30, 2011, and December 31, 2010, equity method investee debt was approximately $514 million and $494 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $257 million and $247 million at June 30, 2011 and December 31, 2010, respectively. |
The following table sets forth details of our (income) loss from unconsolidated investments in power plants for the periods indicated (in millions):
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Greenfield LP |
| $ | 4 |
|
| $ | (3 | ) |
| $ | (1 | ) |
| $ | (7 | ) | ||||
Whitby |
|
| (2 | ) |
|
| (3 | ) |
|
| (6 | ) |
|
| (6 | ) | ||||
Total |
| $ | 2 |
|
| $ | (6 | ) |
| $ | (7 | ) |
| $ | (13 | ) |
Greenfield LP — Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired 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%. Distributions from Greenfield LP were $2 million for both the three and six months ended June 30, 2011. We did not receive any distributions from Greenfield LP during the three and six months ended June 30, 2010.
Whitby — Whitby is a limited partnership between certain subsidiaries of ours and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired simple-cycle cogeneration power plant in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby. Distributions from Whitby were $4 million for both the three and six months ended June 30, 2011, and $2 million for both the three and six months ended June 30, 2010.
Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California which achieved COD on May 3, 2010) from GE that may be exercised between years 7 and 14 after the start of commercial operation. GE 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 GE directs the most significant activities of the power plant including operations and maintenance.
Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which also contains a 25% ownership interest by a third party. We fully consolidate this entity in our Consolidated Condensed Financial Statements and account for the third party ownership interest as a noncontrolling interest under U.S. GAAP.
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4. Comprehensive Loss
Comprehensive loss includes our net loss, unrealized gains and losses from derivative instruments, net of tax that qualify as cash flow hedges, our share of equity method investees‘ OCI and the effects of foreign currency translation adjustments. See Note 7 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 loss for the periods indicated (in millions):
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Net loss |
| $ | (70 | ) |
| $ | (114 | ) |
| $ | (366 | ) |
| $ | (162 | ) | ||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss |
|
| (17 | ) |
|
| (71 | ) |
|
| 14 |
|
|
| 30 |
| ||||
Reclassification adjustment for cash flow hedges realized in net loss |
|
| (31 | ) |
|
| 8 |
|
|
| 44 |
|
|
| 22 |
| ||||
Foreign currency translation loss |
|
| (1 | ) |
|
| (2 | ) |
|
| — |
|
|
| — |
| ||||
Income tax (expense) benefit |
|
| 18 |
|
|
| (23 | ) |
|
| (16 | ) |
|
| (9 | ) | ||||
Comprehensive loss |
|
| (101 | ) |
|
| (202 | ) |
|
| (324 | ) |
|
| (119 | ) | ||||
Add: Comprehensive income attributable to the noncontrolling interest |
|
| — |
|
|
| (1 | ) |
|
| (1 | ) |
|
| — |
| ||||
Comprehensive loss attributable to Calpine |
| $ | (101 | ) |
| $ | (203 | ) |
| $ | (325 | ) |
| $ | (119 | ) |
|
5. Debt
Our debt at June 30, 2011 and December 31, 2010, was as follows (in millions):
|
| June 30, |
|
| December 31, |
| ||||
First Lien Notes(1) |
| $ | 5,891 |
|
| $ | 4,691 |
| ||
Project financing, notes payable and other(2)(3) |
|
| 1,568 |
|
|
| 1,922 |
| ||
Term Loan and New Term Loan(2)(4) |
|
| 1,654 |
|
|
| — |
| ||
NDH Project Debt(4) |
|
| — |
|
|
| 1,258 |
| ||
First Lien Credit Facility(1) |
|
| — |
|
|
| 1,184 |
| ||
CCFC Notes |
|
| 969 |
|
|
| 965 |
| ||
Capital lease obligations |
|
| 234 |
|
|
| 236 |
| ||
Total debt |
|
| 10,316 |
|
|
| 10,256 |
| ||
Less: Current maturities |
|
| 126 |
|
|
| 152 |
| ||
Debt, net of current portion |
| $ | 10,190 |
|
| $ | 10,104 |
|
_________
(1) | On January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed below. |
(2) | On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described below. |
(3) | On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City as further described below. |
(4) | On March 9, 2011, we borrowed $1.3 billion under the Term Loan and repaid and terminated the NDH Project Debt as discussed below. |
Our First Lien Notes and Termination of the First Lien Credit Facility
Our First Lien Notes are summarized in the table below (in millions):
|
| June 30, |
|
| December 31, |
| ||||
2017 First Lien Notes |
| $ | 1,200 |
|
| $ | 1,200 |
| ||
2019 First Lien Notes |
|
| 400 |
|
|
| 400 |
| ||
2020 First Lien Notes |
|
| 1,091 |
|
|
| 1,091 |
| ||
2021 First Lien Notes |
|
| 2,000 |
|
|
| 2,000 |
| ||
2023 First Lien Notes(1) |
|
| 1,200 |
|
|
| — |
| ||
Total First Lien Notes |
| $ | 5,891 |
|
| $ | 4,691 |
|
_________
(1) | On January 14, 2011, we issued $1.2 billion in aggregate principal amount of 7.875% senior secured notes due 2023 in a private placement. The 2023 First Lien Notes bear interest at 7.875% payable semi-annually on January 15 and July 15 of each year, beginning on July 15, 2011. The 2023 First Lien Notes will mature on January 15, 2023. |
Following our emergence from Chapter 11, our First Lien Credit Facility served as our primary debt facility. Beginning in late 2009, we began to repay or exchange our First Lien Credit Facility term loans through proceeds received from the issuances of the First Lien Notes, together with operating cash. On January 14, 2011, we repaid the remaining approximately $1.2 billion from the proceeds from the issuance of the 2023 First Lien Notes, together with operating cash, thereby terminating the First Lien Credit Facility in accordance with its terms.
Our First Lien Notes are secured equally and ratably with indebtedness incurred under our Corporate Revolving Facility, Term Loan and New Term Loan (described below), 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. Repayment of the NDH Project Debt also eliminated the restrictions against our NDH subsidiaries being guarantors to our First Lien Notes and Corporate Revolving Facility. On March 9, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add our NDH subsidiaries as guarantors to our Corporate Revolving Facility and Term Loan. On April 26, 2011, we executed supplemental indentures for the First Lien Notes to add the NDH subsidiaries as guarantors. On June 17, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors of our Corporate Revolving Facility, Term Loan and New Term Loan. On July 22, 2011, we executed supplemental indentures for the First Lien Notes to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors.
Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:
• | incur or guarantee additional first lien indebtedness; |
• | enter into certain types of commodity hedge agreements that can be secured by first lien collateral; |
• | enter into sale and leaseback transactions; |
• | create or incur liens; and |
• | consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis. |
We recorded approximately $19 million in debt extinguishment costs in the first quarter of 2011 from the write-off of unamortized deferred financing costs related to the repayment and termination of the First Lien Credit Facility, and we recorded approximately $22 million of deferred financing costs during the first quarter of 2011 related to the issuance of the 2023 First Lien Notes.
The Term Loan and New Term Loan and Repayment of the NDH Project Debt and Other Project Debt
On March 9, 2011, we entered into and borrowed $1.3 billion under the Term Loan. We used the net proceeds received, together with operating cash on hand to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. The NDH Project Debt was originally established to partially fund the Conectiv Acquisition.
The Term Loan provides for a senior secured term loan facility in an aggregate principal amount of $1.3 billion and bears interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the Term Loan credit agreement), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%.
An aggregate amount equal to 0.25% of the aggregate principal amount of the Term Loan will be payable at the end of each quarter commencing on June 30, 2011, with the remaining balance payable on the maturity date (April 1, 2018). We may elect from time to time to convert all or a portion of the Term Loan from initial LIBOR rate loans to base rate loans or vice versa. In addition, we may at any time, and from time to time, prepay the Term Loan, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent. We may also reprice the Term Loan, subject to approval from the Lenders and subject to a 1% premium if a repricing transaction occurs prior to the first anniversary of the closing date. We may elect to extend the maturity of any term loans under the Term Loan, in whole or in part subject to approval from those lenders holding such term loans. The Term Loan is subject to certain qualifications and exceptions, similar to our First Lien Notes.
If a change of control triggering event occurs, the Company shall notify the Administrative Agent in writing and shall make an offer to prepay the entire principal amount of the Term Loan outstanding within thirty (30) days after the date of such change of control triggering event.
In connection with the Term Loan, the Company and its subsidiaries (subject to certain exceptions) have made certain representations and warranties and are required to comply with various affirmative and negative covenants. The Term Loan 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. If an event of default arises from certain events of bankruptcy or insolvency, all amounts outstanding under the Term Loan will become due and payable immediately without further action or notice. If other events of default arise (as defined in the Credit Agreement) and are continuing, the lenders holding more than 50% of the outstanding Term Loan amounts (as defined in the Credit Agreement) may declare all the Term Loan amounts outstanding to be due and payable immediately.
In connection with the Term Loan, we recorded deferred financing costs of approximately $14 million on our Consolidated Condensed Balance Sheet as of June 30, 2011, and we recorded approximately $74 million in debt extinguishment costs during the first quarter of 2011, which includes approximately $36 million from the write-off of unamortized deferred financing costs, the write-off of approximately $25 million of debt discount and approximately $13 million in prepayment premiums related to the NDH Project Debt.
On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan. The New Term Loan carries substantially the same terms as the Term Loan and matures on April 1, 2018. The New Term Loan also contains very similar covenants, qualifications, exceptions and limitations as the Term Loan and First Lien Notes.
In connection with the New Term Loan, we recorded deferred financing costs of approximately $5 million on our Consolidated Condensed Balance Sheet as of June 30, 2011, and we recorded approximately $5 million in debt extinguishment costs during the three and six months ended June 30, 2011.
Russell City Project Debt
On June 24, 2011, we, through our indirect, partially owned subsidiary Russell City Energy Company, LLC, closed on our approximately $845 million Russell City Project Debt to finance construction of Russell City, a 619 MW combined-cycle power plant under construction in Hayward, CA, which comprises a $700 million construction loan facility, an approximately $77 million project letter of credit facility and a $68 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence and borrowings bear interest initially at LIBOR plus 2.25%. At June 30, 2011, approximately $69 million had been drawn under the construction loan and approximately $61 million of letters of credit were issued under the letter of credit facilities. Calpine‘s pro rata share is 75% and the pro rata share related to the noncontrolling interest is 25%.
In connection with the closing of the Russell City Project Debt, we recorded deferred financing costs of approximately $26 million on our Consolidated Condensed Balance Sheet as of June 30, 2011.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at June 30, 2011, and December 31, 2010 (in millions):
|
| June 30, |
|
| December 31, |
| ||||
Corporate Revolving Facility(1) |
| $ | 369 |
|
| $ | 443 |
| ||
Calpine Development Holdings, Inc. |
|
| 193 |
|
|
| 165 |
| ||
NDH Project Debt credit facility(2) |
|
| — |
|
|
| 34 |
| ||
Various project financing facilities |
|
| 100 |
|
|
| 69 |
| ||
Total |
| $ | 662 |
|
| $ | 711 |
|
_________
(1) | When we entered into our $1.0 billion Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced with letters of credit issued by our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third-party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. |
(2) | We repaid and terminated the NDH Project Debt on March 9, 2011. |
The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate (with the exception of any swingline borrowings, which bear interest at the base rate). Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 2.00% to 2.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers‘ Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 3.00% to 3.25%. Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within 2 business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We will incur an unused commitment fee ranging from 0.50% to 0.75% on the unused amount of commitments under the Corporate Revolving Facility.
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3.0 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures December 10, 2015.
The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors‘ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.
We also have a letter of credit facility related to our subsidiary Calpine Development Holdings, Inc. which matures on December 11, 2012, under which up to $200 million is available for letters of credit.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. We measured the fair value of our debt instruments at June 30, 2011, and December 31, 2010, 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 at June 30, 2011, and December 31, 2010 (in millions):
|
| June 30, 2011 |
|
| December 31, 2010 |
| ||||||||||||||
|
| Fair Value |
|
| Carrying Value |
|
| Fair Value |
|
| Carrying Value |
| ||||||||
First Lien Notes(1) |
| $ | 6,032 |
|
| $ | 5,891 |
|
| $ | 4,695 |
|
| $ | 4,691 |
| ||||
Project financing, notes payable and other(2)(3)(4) |
|
| 1,355 |
|
|
| 1,378 |
|
|
| 1,673 |
|
|
| 1,708 |
| ||||
Term Loan and New Term Loan(1)(2) |
|
| 1,638 |
|
|
| 1,654 |
|
|
| — |
|
|
| — |
| ||||
NDH Project Debt(1) |
|
| — |
|
|
| — |
|
|
| 1,303 |
|
|
| 1,258 |
| ||||
First Lien Credit Facility(1) |
|
| — |
|
|
| — |
|
|
| 1,182 |
|
|
| 1,184 |
| ||||
CCFC Notes |
|
| 1,073 |
|
|
| 969 |
|
|
| 1,067 |
|
|
| 965 |
| ||||
Total |
| $ | 10,098 |
|
| $ | 9,892 |
|
| $ | 9,920 |
|
| $ | 9,806 |
|
_________
(1) | On March 9, 2011, we repaid and terminated the NDH Project Debt with proceeds received from the Term Loan, and on January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed above. |
(2) | On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as described above. |
(3) | On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City as described above. |
(4) | 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. |
|
6. Assets and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and 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 derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); market price levels, primarily for power and natural gas; our credit standing and that of our counterparties; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas 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 can also be 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 our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of natural gas swaps, futures and options traded on the NYMEX.
Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from markets such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are primarily industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments 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 at June 30, 2011, and December 31, 2010, 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 |
| |||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
|
| (in millions) |
| |||||||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash equivalents(1) |
| $ | 1,334 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,334 |
| ||||
Margin deposits |
|
| 133 |
|
|
| — |
|
|
| — |
|
|
| 133 |
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
|
| 460 |
|
|
| — |
|
|
| — |
|
|
| 460 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 173 |
|
|
| 45 |
|
|
| 218 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
| ||||
Total assets |
| $ | 1,927 |
|
| $ | 174 |
|
| $ | 45 |
|
| $ | 2,146 |
| ||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
| $ | 414 |
|
| $ | — |
|
| $ | — |
|
| $ | 414 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 112 |
|
|
| 24 |
|
|
| 136 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 314 |
|
|
| — |
|
|
| 314 |
| ||||
Total liabilities |
| $ | 414 |
|
| $ | 426 |
|
| $ | 24 |
|
| $ | 864 |
|
|
| Assets and Liabilities with Recurring Fair Value Measures |
| |||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
|
| (in millions) |
| |||||||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash equivalents(1) |
| $ | 1,297 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,297 |
| ||||
Margin deposits |
|
| 162 |
|
|
| — |
|
|
| — |
|
|
| 162 |
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
|
| 550 |
|
|
| — |
|
|
| — |
|
|
| 550 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 287 |
|
|
| 54 |
|
|
| 341 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 4 |
|
|
| — |
|
|
| 4 |
| ||||
Total assets |
| $ | 2,009 |
|
| $ | 291 |
|
| $ | 54 |
|
| $ | 2,354 |
| ||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Margin deposits held by us posted by our counterparties |
| $ | 6 |
|
| $ | — |
|
| $ | — |
|
| $ | 6 |
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
|
| 574 |
|
|
| — |
|
|
| — |
|
|
| 574 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 119 |
|
|
| 24 |
|
|
| 143 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 371 |
|
|
| — |
|
|
| 371 |
| ||||
Total liabilities |
| $ | 580 |
|
| $ | 490 |
|
| $ | 24 |
|
| $ | 1,094 |
|
_________
(1) | At June 30, 2011, and December 31, 2010, we had cash equivalents of $1,144 million and $1,094 million included in cash and cash equivalents and $190 million and $203 million included in restricted cash, respectively. |
(2) | Includes OTC swaps and options. |
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Balance, beginning of period |
| $ | 12 |
|
| $ | 57 |
|
| $ | 30 |
|
| $ | 38 |
| ||||
Realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Included in net loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Included in operating revenues(1) |
|
| 10 |
|
|
| 10 |
|
|
| 6 |
|
|
| 29 |
| ||||
Included in fuel and purchased energy expense(2) |
|
| 1 |
|
|
| (3 | ) |
|
| — |
|
|
| (3 | ) | ||||
Included in OCI |
|
| 4 |
|
|
| (5 | ) |
|
| 5 |
|
|
| — |
| ||||
Purchases, issuances, sales and settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Purchases |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
|
| — |
| ||||
Settlements |
|
| (7 | ) |
|
| (16 | ) |
|
| (21 | ) |
|
| (22 | ) | ||||
Transfers into and/or out of level 3:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Transfers out of level 3(4) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
| ||||
Balance, end of period |
| $ | 21 |
|
| $ | 43 |
|
| $ | 21 |
|
| $ | 43 |
| ||||
Change in unrealized gains relating to instruments held at end of period |
| $ | 11 |
|
| $ | 7 |
|
| $ | 7 |
|
| $ | 26 |
|
_________
(1) | For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations. |
(2) | For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. |
(3) | We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no significant transfers into/out of level 1 or out of level 2 or into level 3 during the three and six months ended June 30, 2011 and 2010. |
(4) | There were no significant transfers into level 2 or out of level 3 for the three months ended June 30, 2011 and 2010, and the six months ended June 30, 2011. We had $(1) million in losses transferred out of level 3 into level 2 for the six months ended June 30, 2010. Transfers out of level 3 into level 2 were due to changes in market liquidity in various power markets. |
|
7. Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates.
At June 30, 2011, the maximum length of time that our PPAs extend is approximately 24 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 15 years, respectively.
At June 30, 2011 and December 31, 2010, 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 |
| |||||||
|
| June 30, |
|
| December 31, |
| ||||
Derivative Instruments |
|
|
|
|
|
|
|
| ||
Power (MWh) |
|
| (40 | ) |
|
| (50 | ) | ||
Natural gas (MMBtu) |
|
| 170 |
|
|
| 31 |
| ||
Interest rate swaps(1) |
| $ | 5,191 |
|
| $ | 6,171 |
|
_________
(1) | Approximately $4.1 billion and $3.3 billion at June 30, 2011 and December 31, 2010, respectively, related to variable rate debt that was converted to fixed rate debt in 2011 and 2010. |
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(ies) 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 at June 30, 2011, was $48 million for which we have posted collateral of $3 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our Corporate Revolving Facility. If our credit rating were downgraded, we estimate that additional collateral of approximately $21 million would be required and that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge 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 or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans or interest rate swap breakage costs associated with interest rate swaps formerly hedging project debt) 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 swaps), fuel and purchased energy expense (for natural gas contracts and swaps) and interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings, or until it is determined that the forecasted transaction is probable of not occurring. Upon repayment of our NDH Project Debt and other project debt, we terminated and settled the interest rate swaps related to these debt instruments and recorded $17 million to (gain) loss on interest rate derivatives, net for both the three months and six months ended June 30, 2011. See Note 5 for further information about the repayment of the NDH Project Debt as well as the repayment of other project debt with proceeds from our New Term Loan.
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 except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility and Other Project Debt — During 2010, we repaid approximately $3.5 billion of our First Lien Credit Facility term loans, which had approximately $3.3 billion notional amount of interest rate swaps hedging the scheduled variable interest payments, and in January 2011, we repaid the remaining approximately $1.2 billion of First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps hedging the scheduled variable interest payments. With the repayment of the remaining First Lien Credit Facility term loans, the remaining unrealized losses of approximately $91 million in AOCI related to the interest swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into income as an additional (gain) loss on interest rate derivatives, net, during the first quarter of 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to (gain) loss on interest rate derivatives, net during the second quarter of 2011 resulting from the repayment of project debt in June 2011. We have presented the reclassification of unrealized losses from AOCI into income and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as (gain) loss on interest rate derivatives, net on our Consolidated Condensed Statements of Operations. We also have determined that, based upon current market conditions and consistent with our risk management policy, liquidation of these interest rate swaps is not economically beneficial and additional future losses are limited. Accordingly, we have elected to retain and hold these interest rate swap positions at this time.
Derivatives Included on Our Consolidated Condensed Balance Sheets
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by hedge type and location at June 30, 2011, and December 31, 2010 (in millions):
|
| June 30, 2011 |
| ||||||||||||
|
| Interest Rate |
|
| Commodity |
|
| Total Derivative |
| ||||||
Balance Sheet Presentation |
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative assets |
| $ | — |
|
| $ | 569 |
|
| $ | 569 |
| |||
Long-term derivative assets |
|
| 1 |
|
|
| 109 |
|
|
| 110 |
| |||
Total derivative assets |
| $ | 1 |
|
| $ | 678 |
|
| $ | 679 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative liabilities |
| $ | 195 |
|
| $ | 448 |
|
| $ | 643 |
| |||
Long-term derivative liabilities |
|
| 119 |
|
|
| 102 |
|
|
| 221 |
| |||
Total derivative liabilities |
| $ | 314 |
|
| $ | 550 |
|
| $ | 864 |
| |||
Net derivative assets (liabilities) |
| $ | (313 | ) |
| $ | 128 |
|
| $ | (185 | ) |
|
| December 31, 2010 |
| ||||||||||||
|
| Interest Rate |
|
| Commodity |
|
| Total Derivative |
| ||||||
Balance Sheet Presentation |
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative assets |
| $ | — |
|
| $ | 725 |
|
| $ | 725 |
| |||
Long-term derivative assets |
|
| 4 |
|
|
| 166 |
|
|
| 170 |
| |||
Total derivative assets |
| $ | 4 |
|
| $ | 891 |
|
| $ | 895 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative liabilities |
| $ | 197 |
|
| $ | 521 |
|
| $ | 718 |
| |||
Long-term derivative liabilities |
|
| 174 |
|
|
| 196 |
|
|
| 370 |
| |||
Total derivative liabilities |
| $ | 371 |
|
| $ | 717 |
|
| $ | 1,088 |
| |||
Net derivative assets (liabilities) |
| $ | (367 | ) |
| $ | 174 |
|
| $ | (193 | ) |
|
| June 30, 2011 |
|
| December 31, 2010 |
| ||||||||||||||
|
| Fair Value of |
|
| Fair Value of |
|
| Fair Value of |
|
| Fair Value of |
| ||||||||
Derivatives designated as cash flow hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | — |
|
| $ | 49 |
|
| $ | 2 |
|
| $ | 143 |
| ||||
Commodity instruments |
|
| 104 |
|
|
| 41 |
|
|
| 161 |
|
|
| 52 |
| ||||
Total derivatives designated as cash flow hedging instruments |
| $ | 104 |
|
| $ | 90 |
|
| $ | 163 |
|
| $ | 195 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | 1 |
|
| $ | 265 |
|
| $ | 2 |
|
| $ | 228 |
| ||||
Commodity instruments |
|
| 574 |
|
|
| 509 |
|
|
| 730 |
|
|
| 665 |
| ||||
Total derivatives not designated as hedging instruments |
| $ | 575 |
|
| $ | 774 |
|
| $ | 732 |
|
| $ | 893 |
| ||||
Total derivatives |
| $ | 679 |
|
| $ | 864 |
|
| $ | 895 |
|
| $ | 1,088 |
|
Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our net 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 June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Realized gain (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | (60 | ) |
| $ | (6 | ) |
| $ | (106 | ) |
| $ | (12 | ) | ||||
Commodity derivative instruments |
|
| 42 |
|
|
| 59 |
|
|
| 52 |
|
|
| 52 |
| ||||
Total realized gain (loss) |
| $ | (18 | ) |
| $ | 53 |
|
| $ | (54 | ) |
| $ | 40 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Unrealized gain (loss)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | 24 |
|
| $ | (16 | ) |
| $ | (38 | ) |
| $ | (19 | ) | ||||
Commodity derivative instruments |
|
| 26 |
|
|
| (31 | ) |
|
| (39 | ) |
|
| 81 |
| ||||
Total unrealized gain (loss) |
| $ | 50 |
|
| $ | (47 | ) |
| $ | (77 | ) |
| $ | 62 |
| ||||
Total mark-to-market activity |
| $ | 32 |
|
| $ | 6 |
|
| $ | (131 | ) |
| $ | 102 |
|
_________
(1) | Changes in unrealized gain (loss) include de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Realized and unrealized gain (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Power contracts included in operating revenues |
| $ | 48 |
|
| $ | 41 |
|
| $ | (9 | ) |
| $ | 12 |
| ||||
Natural gas contracts included in fuel and purchased energy expense |
|
| 20 |
|
|
| (13 | ) |
|
| 22 |
|
|
| 121 |
| ||||
Interest rate swaps included in interest expense |
|
| 1 |
|
|
| (30 | ) |
|
| 2 |
|
|
| (28 | ) | ||||
Gain (loss) on interest rate derivatives, net |
|
| (37 | ) |
|
| 8 |
|
|
| (146 | ) |
|
| (3 | ) | ||||
Total mark-to-market activity |
| $ | 32 |
|
| $ | 6 |
|
| $ | (131 | ) |
| $ | 102 |
|
Derivatives Included in Our 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 June 30, |
| |||||||||||||||||||||||||||
|
| Gain (Loss) Recognized in OCI (Effective Portion) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Effective Portion)(2) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Ineffective Portion) |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Interest rate swaps |
| $ | (9 | ) |
| $ | (16 | ) |
| $ | (22 | ) |
| $ | (62 | ) |
| $ | (1 | ) |
| $ | — |
| ||||||
Commodity derivative instruments |
|
| (39 | ) |
|
| (47 | ) |
|
| 53 |
|
|
| 54 |
|
|
| 1 |
|
|
| 3 |
| ||||||
Total |
| $ | (48 | ) |
| $ | (63 | ) |
| $ | 31 |
|
| $ | (8 | ) |
| $ | — |
|
| $ | 3 |
|
|
| Six Months Ended June 30, |
| |||||||||||||||||||||||||||
|
| Gain (Loss) Recognized in OCI (Effective Portion) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Effective Portion)(2) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Ineffective Portion) |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Interest rate swaps |
| $ | 94 |
|
| $ | (27 | ) |
| $ | (123 | )(4) |
| $ | (122 | ) |
| $ | (1 | ) |
| $ | — |
| ||||||
Commodity derivative instruments |
|
| (36 | ) |
|
| 79 |
|
|
| 79 | (1) |
|
| 100 |
|
|
| 1 |
|
|
| 1 |
| ||||||
Total |
| $ | 58 |
|
| $ | 52 |
|
| $ | (44 | ) |
| $ | (22 | ) |
| $ | — |
|
| $ | 1 |
|
_________
(1) | Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations. |
(2) | Cumulative cash flow hedge losses remaining in AOCI were $81 million and $122 million at June 30, 2011 and December 31, 2010, respectively. |
(3) | Reclassification of losses from OCI to earnings for the three months ended June 30, 2011 consisted of $7 million in losses from the reclassification of interest rate contracts due to settlement and $15 million in losses from terminated interest rate contracts due to the repayment of project debt in June 2011. |
(4) | Reclassification of losses from OCI to earnings for the six months ended June 30, 2011 consisted of $17 million in losses from the reclassification of interest rate contracts due to settlement, $15 million in losses from terminated interest rate contracts due to the repayment of project debt in June 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinance of variable rate First Lien Credit Facility term loans. |
Assuming constant June 30, 2011, power and natural gas prices and interest rates, we estimate that pre-tax net gains of $45 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.
|
8. 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 Corporate Revolving Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under our Corporate Revolving 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 pro rata with the lenders under our Corporate Revolving Facility, First Lien Notes, Term Loan and New Term Loan.
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 at June 30, 2011, and December 31, 2010 (in millions):
|
| June 30, |
|
| December 31, |
| ||||
Margin deposits(1) |
| $ | 133 |
|
| $ | 162 |
| ||
Natural gas and power prepayments |
|
| 49 |
|
|
| 43 |
| ||
Total margin deposits and natural gas and power prepayments with our counterparties(2) |
| $ | 182 |
|
| $ | 205 |
| ||
|
|
|
|
|
|
|
|
| ||
Letters of credit issued(3) |
| $ | 492 |
|
| $ | 588 |
| ||
First priority liens under power and natural gas agreements(4) |
|
| — |
|
|
| — |
| ||
First priority liens under interest rate swap agreements |
|
| 299 |
|
|
| 356 |
| ||
Total letters of credit and first priority liens with our counterparties |
| $ | 791 |
|
| $ | 944 |
| ||
|
|
|
|
|
|
|
|
| ||
Margin deposits held by us posted by our counterparties(1)(5) |
| $ | — |
|
| $ | 6 |
| ||
Letters of credit posted with us by our counterparties |
|
| 36 |
|
|
| 66 |
| ||
Total margin deposits and letters of credit posted with us by our counterparties |
| $ | 36 |
|
| $ | 72 |
|
_________
(1) | Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation. |
(2) | At June 30, 2011 and December 31, 2010, $158 million and $183 million were included in margin deposits and other prepaid expense, respectively, and $24 million and $22 million were included in other assets at June 30, 2011 and December 31, 2010, respectively, on our Consolidated Condensed Balance Sheets. |
(3) | When we entered into our Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit issued under our Corporate Revolving Facility used for our commodity procurement and risk management activities at December 31, 2010 include those that were back-stopped of approximately $63 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. |
(4) | At June 30, 2011, and December 31, 2010, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $99 million and $193 million, respectively; therefore, there was no collateral exposure at June 30, 2011, or December 31, 2010. |
(5) | 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.
|
9. Income Taxes
The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest), and our imputed tax rates, as well as intraperiod tax allocations for the periods indicated (in millions):
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Income tax expense (benefit) |
| $ | 18 |
|
| $ | 6 |
|
| $ | (65 | )(1) |
| $ | 17 | (2) | ||||
Imputed tax rate |
|
| (35 | )% |
|
| (5 | )% |
|
| 15 | % |
|
| (11 | )% | ||||
Intraperiod tax allocation expense (benefit) |
| $ | 18 |
|
| $ | (31 | ) |
| $ | (16 | ) |
| $ | (17 | ) |
_________
(1) | Includes a tax benefit of approximately $76 million related to the consolidation of the CCFC and Calpine groups for federal income tax reporting purposes for the six months ended June 30, 2011 (as described below). |
(2) | Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI. |
Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) and income from discontinued operations with an offsetting amount recognized in OCI and discontinued operations. The following table details the effects of our intraperiod tax allocations for the three and six months ended June 30, 2011 and 2010 (in millions).
|
| Three Months Ended June 30, |
| |||||||||||||||||||||||||||
|
| Included in continuing |
|
| Included in discontinued operations |
|
| Included in OCI |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Intraperiod tax allocation expense (benefit) |
| $ | 18 |
|
| $ | (31 | ) |
| $ | — |
|
| $ | 8 |
|
| $ | (18 | ) |
| $ | 23 |
|
|
| Six Months Ended June 30, |
| |||||||||||||||||||||||||||
|
| Included in continuing |
|
| Included in discontinued operations |
|
| Included in OCI |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Intraperiod tax allocations expense (benefit) |
| $ | (16 | ) |
| $ | (17 | ) |
| $ | — |
|
| $ | 8 |
|
| $ | 16 |
|
| $ | 9 |
|
Accounting for Income Taxes
Consolidation of CCFC and Calpine Tax Reporting Groups — For federal income tax reporting purposes, our historical tax reporting group was comprised primarily of two separate groups, CCFC and its subsidiaries, which we referred to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we referred to as the Calpine group. During the first quarter of 2011, we elected to consolidate our CCFC and Calpine groups for federal income tax reporting purposes and Calpine will file a consolidated federal income tax return for the year ended December 31, 2011 that will include the CCFC group. As a result of the consolidation, the CCFC group deferred tax liabilities will be eligible to offset existing Calpine group NOLs that were reserved by a valuation allowance. Accordingly, we recorded a one-time federal deferred income tax benefit of approximately $76 million during the first quarter of 2011 to reduce our valuation allowance. For the three and six months ended June 30, 2010, the CCFC group was deconsolidated from the Calpine group for federal income tax reporting purposes.
For the three and six months ended June 30, 2011 and 2010, we used the effective rate method to determine both the CCFC and Calpine groups‘ tax provision, as applicable; however, our income tax rates did not bear a customary relationship to statutory income tax rates primarily as a result of the consolidation of the CCFC and Calpine groups for 2011, the impact of state income taxes, changes in unrecognized tax benefits, the Calpine group valuation allowance and intraperiod tax allocations.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses in prior periods, we are unable to assume future profits; however, since our emergence from Chapter 11, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits and Liabilities — At June 30, 2011, we had unrecognized tax benefits of $88 million. If recognized, $41 million of our unrecognized tax benefits could impact the annual effective tax rate and $47 million related to deferred tax assets could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $21 million for income tax matters at June 30, 2011. The amount of unrecognized tax benefits at June 30, 2011 remained comparable to the amount of unrecognized tax benefits at December 31, 2010. We believe it is reasonably possible that a decrease within the range of approximately $13 million and $16 million in unrecognized tax benefits could occur within the next 12 months primarily related to federal tax liabilities, 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. At December 31, 2010, approximately $2.5 billion of our $7.4 billion total NOLs remain subject to annual section 382 limitations with the remaining $4.9 billion no longer subject to the Section 382 limitation. If a subsequent ownership change were to occur as a result of future transactions in our common stock, accompanied by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited.
Under state income tax laws, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the Internal Revenue Code. We are analyzing the effect of our change in ownership on the Effective Date for each of our significant states to determine the amount of our NOL limitation. The analysis will also determine our state NOLs expected to expire unutilized as a result of the cessation of business operations and changes in apportionment as of the Effective Date. Although our analysis is not complete, we believe that the statutory limitations on the use of some of our pre-emergence state NOLs will cause them to expire unutilized. We believe our analysis could result in a reduction of available state NOLs, which had a full valuation allowance at June 30, 2011 and December 31, 2010. Upon completion of the analysis, we will reduce our deferred tax asset for state NOLs that we are unable to utilize and make an equal reduction in our valuation allowance. The result is not expected to have an effect on our income tax expense in 2011.
We have certain intercompany accounts payable / receivable balances that we will be eliminating as part of the final steps of our emergence from bankruptcy. We are analyzing the federal and state income tax effects of eliminating these balances and, although our analysis is not complete, we believe that the elimination of some of these pre-petition intercompany balances will have the ultimate effect of recharacterizing a portion of our federal and state ordinary NOLs into either capital losses, which has a shorter carryforward period, or increasing the tax basis in our affiliates, a portion of which will not be recognized until the related entity is sold. Certain of these recharacterizations may result in a reduction of our gross deferred tax asset along with an equal reduction in our valuation allowance. The elimination of these intercompany account balances is not expected to have an effect on our income tax expense in 2011.
The State of California enacted legislation in 2010 suspending the ability of taxpayers to use NOLs for tax years 2010 and 2011; however, they have extended the 20 year carryforward period to account for the suspension period.
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, an ownership change of 25 percentage points has occurred; however, we have not experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization. Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the foregoing events were to occur together and our Board of Directors was to elect to impose them, they could become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from occurring.
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.
Income Tax Audits —We remain subject to various audits and reviews by taxing authorities; however, we do not expect these will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to U.S. Internal Revenue Service examination regardless of when the NOLs occurred. Due to significant NOLs, any adjustment of state returns or federal returns from 2007 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.
|
11. Stock-Based Compensation
The Calpine Equity Incentive Plans 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. 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 approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At June 30, 2011, there are 567,000 and 27,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively.
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model 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 $7 million and $6 million for the three months ended June 30, 2011 and 2010, respectively, and $12 million for both the six months ended June 30, 2011 and 2010. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the three and six months ended June 30, 2011 and 2010. At June 30, 2011, there was unrecognized compensation cost of $17 million related to options, $22 million related to restricted stock and $1 million related to restricted stock units, which is expected to be recognized over a weighted average period of 1.6 years for options, 1.8 years for restricted stock and 0.9 years for restricted stock units. We issue new shares from our reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2011, is as follows:
|
| Number of Shares |
|
| Weighted Average Exercise Price |
|
| Weighted Average Remaining Term |
|
| Aggregate Intrinsic Value |
| ||||||||
Outstanding - December 31, 2010 |
|
| 17,164,890 |
|
| $ | 17.44 |
|
|
| 5.6 |
|
| $ | 8 |
| ||||
Granted |
|
| 909,306 |
|
| $ | 14.32 |
|
|
|
|
|
|
|
|
| ||||
Exercised |
|
| 6,654 |
|
| $ | 10.95 |
|
|
|
|
|
|
|
|
| ||||
Forfeited |
|
| 51,050 |
|
| $ | 11.23 |
|
|
|
|
|
|
|
|
| ||||
Expired |
|
| 156,885 |
|
| $ | 17.55 |
|
|
|
|
|
|
|
|
| ||||
Outstanding - June 30, 2011 |
|
| 17,859,607 |
|
| $ | 17.30 |
|
|
| 5.3 |
|
| $ | 25 |
| ||||
Exercisable - June 30, 2011 |
|
| 6,665,499 |
|
| $ | 19.15 |
|
|
| 5.3 |
|
| $ | 1 |
| ||||
Vested and expected to vest - June 30, 2011 |
|
| 17,443,021 |
|
| $ | 17.41 |
|
|
| 5.2 |
|
| $ | 24 |
|
The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the six months ended June 30, 2011 and 2010.
The fair value of options granted during the six months ended June 30, 2011 and 2010, was determined on the grant date using the Black-Scholes pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.
|
| 2011 |
|
| 2010 |
| ||||
Expected term (in years)(1) |
|
| 6.5 |
|
|
| 6.5 |
| ||
Risk-free interest rate(2) |
|
| 2.7 — 3.2 | % |
|
| 2.9 — 3.3 | % | ||
Expected volatility(3) |
|
| 31.2 — 31.7 | % |
|
| 35.0 — 37.6 | % | ||
Dividend yield(4) |
|
| — |
|
|
| — |
| ||
Weighted average grant-date fair value (per option) |
| $ | 5.48 |
|
| $ | 4.66 |
|
_________
(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 have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future. |
No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2011, is as follows:
|
| Number of |
|
| Weighted |
| ||||
Nonvested - December 31, 2010 |
|
| 2,683,117 |
|
| $ | 11.16 |
| ||
Granted |
|
| 1,630,465 |
|
| $ | 14.38 |
| ||
Forfeited |
|
| 145,923 |
|
| $ | 11.88 |
| ||
Vested |
|
| 460,232 |
|
| $ | 14.62 |
| ||
Nonvested - June 30, 2011 |
|
| 3,707,427 |
|
| $ | 12.10 |
|
The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2011 and 2010, was $7 million and $4 million, respectively.
|
12. Commitments and Contingencies
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect to our financial position, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect to our financial position, results of operations or cash flows. Further, 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.
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 seeking to enjoin further exploration, construction and development of the Calpine Four-Mile Hill Project in the Glass Mountain and Medicine Lake geothermal areas. The 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 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. As reported last quarter, on November 4, 2010, the United States District for the Eastern District of California entered an order remanding the matter to federal agencies to implement the Court‘s order. We consider this matter closed and anticipate it will take the federal agencies at least one year to implement the Court‘s order to conduct additional analysis.
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 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, and we are in communication with the U.S. Department of Justice regarding how to proceed.
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. A summary of our larger environmental matters are 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 or paid $10 million related to these liabilities at June 30, 2011. Pursuant to the Conectiv Purchase Agreement, PHI is responsible for any amounts that exceed $10 million associated with New Jersey environmental remediation liabilities. Our accrual is included in our allocation of the Conectiv Acquisition purchase price. See Note 2 for disclosures related to our Conectiv Acquisition.
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 to limit emissions of pollutants that are not subject to measurement by continuous emissions monitoring systems. These restrictions required one of our peaker power plants (Deepwater Unit 1) to operate at approximately 8 MW less than its full capacity of 86 MW. As part of the settlement reached with the NJDEP, we submitted an application to modify the Deepwater Unit 1 air permit to reclaim the 8 MW limitation and the application was recently approved. We received a permit to allow Deepwater Unit 1 to operate at approximately 86 MW versus the 78 MW restriction during the appeal process. We continue settlement discussions with NJDEP regarding the modification of permits for the other peaker power plants and those appeals remain pending.
Other Contingencies
Distribution of Calpine Common Stock under our Plan of Reorganization — Through the filing of this Report, approximately 464 million shares have been distributed to holders of allowed unsecured claims and approximately 21 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. Holders of the CalGen Third Lien Debt made assertions that they continued 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. On June 2, 2011, we reached a settlement with holders of the CalGen Third Lien Debt which will be funded from the sale of a portion of the shares held in reserve. The balance of the reserve shares are expected to be distributed to the remaining unsecured creditors over the next few months in accordance with our Plan of Reorganization. The exact timing and number of shares to be distributed will be subject to our final calculation. The sale of shares or the distribution of the remaining shares does not represent the issuance of new or additional shares and will have no impact on our results of operations, financial position or cash flows. The bankruptcy court approved the settlement with the CalGen Third Lien Debt claimants on June 16, 2011. The settlement agreements with the CalGen Third Lien Debt claimants and the claims purchasers are expected to be fully implemented by early August.
|
13. Segment Information
We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At June 30, 2011, our reportable segments were West (including geothermal), Texas, North (including Canada and the assets purchased in the Conectiv Acquisition) 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 physical 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 including natural gas transactions hedging future power sales 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 North segment information for the three and six months ended June 30, 2011, includes the financial results of the assets we acquired from Conectiv, with no similar revenues and expenses included for the three and six months ended June 30, 2010. See Note 2 for further information about our Conectiv Acquisition.
|
| Three Months Ended June 30, 2011 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 466 |
|
| $ | 646 |
|
| $ | 324 |
|
| $ | 197 |
|
| $ | — |
|
| $ | 1,633 |
| ||||||
Intersegment revenues |
|
| 1 |
|
|
| 5 |
|
|
| 5 |
|
|
| 40 |
|
|
| (51 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 467 |
|
| $ | 651 |
|
| $ | 329 |
|
| $ | 237 |
|
| $ | (51 | ) |
| $ | 1,633 |
| ||||||
Commodity Margin |
| $ | 236 |
|
| $ | 128 |
|
| $ | 179 |
|
| $ | 59 |
|
| $ | — |
|
| $ | 602 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 11 |
|
|
| 27 |
|
|
| — |
|
|
| — |
|
|
| (9 | ) |
|
| 29 |
| ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 116 |
|
|
| 63 |
|
|
| 47 |
|
|
| 41 |
|
|
| (6 | ) |
|
| 261 |
| ||||||
Depreciation and amortization expense |
|
| 42 |
|
|
| 35 |
|
|
| 33 |
|
|
| 22 |
|
|
| (1 | ) |
|
| 131 |
| ||||||
Sales, general and other administrative expense |
|
| 8 |
|
|
| 13 |
|
|
| 6 |
|
|
| 6 |
|
|
| 1 |
|
|
| 34 |
| ||||||
Other operating expenses(2) |
|
| 11 |
|
|
| 3 |
|
|
| 9 |
|
|
| 2 |
|
|
| (5 | ) |
|
| 20 |
| ||||||
Loss from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| 2 |
| ||||||
Income (loss) from operations |
|
| 70 |
|
|
| 41 |
|
|
| 82 |
|
|
| (12 | ) |
|
| 2 |
|
|
| 183 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 190 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 37 |
| ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 8 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (52 | ) |
|
| Three Months Ended June 30, 2010 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 525 |
|
| $ | 552 |
|
| $ | 134 |
|
| $ | 219 |
|
| $ | — |
|
| $ | 1,430 |
| ||||||
Intersegment revenues |
|
| 1 |
|
|
| 6 |
|
|
| 1 |
|
|
| 21 |
|
|
| (29 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 526 |
|
| $ | 558 |
|
| $ | 135 |
|
| $ | 240 |
|
| $ | (29 | ) |
| $ | 1,430 |
| ||||||
Commodity Margin |
| $ | 258 |
|
| $ | 128 |
|
| $ | 79 |
|
| $ | 68 |
|
| $ | — |
|
| $ | 533 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 10 |
|
|
| (10 | ) |
|
| 3 |
|
|
| (9 | ) |
|
| (6 | ) |
|
| (12 | ) | ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 88 |
|
|
| 78 |
|
|
| 23 |
|
|
| 31 |
|
|
| (7 | ) |
|
| 213 |
| ||||||
Depreciation and amortization expense |
|
| 50 |
|
|
| 40 |
|
|
| 19 |
|
|
| 27 |
|
|
| (1 | ) |
|
| 135 |
| ||||||
Sales, general and other administrative expense |
|
| 11 |
|
|
| 16 |
|
|
| 22 |
|
|
| 2 |
|
|
| (1 | ) |
|
| 50 |
| ||||||
Other operating expenses(2) |
|
| 12 |
|
|
| (5 | ) |
|
| 7 |
|
|
| (1 | ) |
|
| 8 |
|
|
| 21 |
| ||||||
(Income) from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| (6 | ) |
|
| — |
|
|
| — |
|
|
| (6 | ) | ||||||
Income (loss) from operations |
|
| 107 |
|
|
| (11 | ) |
|
| 17 |
|
|
| — |
|
|
| (5 | ) |
|
| 108 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 220 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (8 | ) | ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 8 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (112 | ) |
|
| Six Months Ended June 30, 2011 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 1,065 |
|
| $ | 1,096 |
|
| $ | 595 |
|
| $ | 376 |
|
| $ | — |
|
| $ | 3,132 |
| ||||||
Intersegment revenues |
|
| 4 |
|
|
| 10 |
|
|
| 13 |
|
|
| 85 |
|
|
| (112 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 1,069 |
|
| $ | 1,106 |
|
| $ | 608 |
|
| $ | 461 |
|
| $ | (112 | ) |
| $ | 3,132 |
| ||||||
Commodity Margin |
| $ | 469 |
|
| $ | 195 |
|
| $ | 314 |
|
| $ | 113 |
|
| $ | — |
|
| $ | 1,091 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 16 |
|
|
| (33 | ) |
|
| 4 |
|
|
| (4 | ) |
|
| (15 | ) |
|
| (32 | ) | ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 203 |
|
|
| 143 |
|
|
| 92 |
|
|
| 74 |
|
|
| (13 | ) |
|
| 499 |
| ||||||
Depreciation and amortization expense |
|
| 88 |
|
|
| 65 |
|
|
| 66 |
|
|
| 45 |
|
|
| (2 | ) |
|
| 262 |
| ||||||
Sales, general and other administrative expense |
|
| 19 |
|
|
| 23 |
|
|
| 12 |
|
|
| 11 |
|
|
| 1 |
|
|
| 66 |
| ||||||
Other operating expenses(2) |
|
| 19 |
|
|
| 3 |
|
|
| 16 |
|
|
| 3 |
|
|
| (3 | ) |
|
| 38 |
| ||||||
(Income) from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| (7 | ) |
|
| — |
|
|
| — |
|
|
| (7 | ) | ||||||
Income (loss) from operations |
|
| 156 |
|
|
| (72 | ) |
|
| 139 |
|
|
| (24 | ) |
|
| 2 |
|
|
| 201 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 378 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 146 |
| ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 108 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (431 | ) |
|
| Six Months Ended June 30, 2010 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 1,190 |
|
| $ | 1,079 |
|
| $ | 257 |
|
| $ | 418 |
|
| $ | — |
|
| $ | 2,944 |
| ||||||
Intersegment revenues |
|
| 5 |
|
|
| 10 |
|
|
| 2 |
|
|
| 44 |
|
|
| (61 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 1,195 |
|
| $ | 1,089 |
|
| $ | 259 |
|
| $ | 462 |
|
| $ | (61 | ) |
| $ | 2,944 |
| ||||||
Commodity Margin |
| $ | 471 |
|
| $ | 235 |
|
| $ | 131 |
|
| $ | 126 |
|
| $ | — |
|
| $ | 963 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 18 |
|
|
| 86 |
|
|
| — |
|
|
| 13 |
|
|
| (14 | ) |
|
| 103 |
| ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 178 |
|
|
| 162 |
|
|
| 45 |
|
|
| 59 |
|
|
| (13 | ) |
|
| 431 |
| ||||||
Depreciation and amortization expense |
|
| 103 |
|
|
| 76 |
|
|
| 39 |
|
|
| 56 |
|
|
| (3 | ) |
|
| 271 |
| ||||||
Sales, general and other administrative expense |
|
| 26 |
|
|
| 16 |
|
|
| 25 |
|
|
| 6 |
|
|
| (1 | ) |
|
| 72 |
| ||||||
Other operating expenses(2) |
|
| 29 |
|
|
| 2 |
|
|
| 15 |
|
|
| 2 |
|
|
| (1 | ) |
|
| 47 |
| ||||||
(Income) from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| (13 | ) |
|
| — |
|
|
| — |
|
|
| (13 | ) | ||||||
Income from operations |
|
| 153 |
|
|
| 65 |
|
|
| 20 |
|
|
| 16 |
|
|
| 4 |
|
|
| 258 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 399 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 3 |
| ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 13 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (157 | ) |
_________
(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 $2 million and $5 million of RGGI compliance and other environmental costs for the three months ended June 30, 2011 and 2010, respectively, and $4 million and $5 million for the six months ended June 30, 2011 and 2010, respectively, which are included as a component of Commodity Margin. |
|
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, 2010, included in our 2010 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.
Reclassifications Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the three and six months ended June 30, 2010 to conform to the current period presentation. Our reclassifications are summarized as follows:
We have reclassified amounts attributable to interest rate swaps formerly hedging our First Lien Credit Facility term loans previously recorded in interest expense to (gain) loss on interest rate derivatives, net of approximately $(8) million and $3 million for the three and six months ended June 30, 2010, respectively. See Note 7 for further information about our interest rate swaps formerly hedging our First Lien Credit Facility.
We have reclassified depreciation expense on corporate assets previously recorded in sales, general and other administrative expense to depreciation and amortization expense of approximately $ 3 million and $ 6 million for the three and six months ended June 30, 2010, respectively.
We have reclassified cash payments on our interest rate swaps formerly hedging our First Lien Credit Facility term loans previously included in net cash provided by operating activities of approximately $ 14 million to settlement of non-hedging interest rate swaps included in net cash provided by (used in) investing activities for the six months ended June 30, 2010.
Use of Estimates in Preparation of Financial Statements The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At June 30, 2011, and December 31, 2010, we had cash and cash equivalents of $ 301 million and $ 269 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Consolidated Condensed Statements of Cash Flows. The table below represents the components of our restricted cash at June 30, 2011, and December 31, 2010 (in millions):
Inventory At June 30, 2011 and December 31, 2010, we had inventory of $ 246 million and $ 262 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost under the weighted average cost method or market value. Spare parts inventory is valued at the weighted average cost and are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge 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 or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans or interest rate swap breakage costs associated with interest rate swaps formerly hedging project debt) 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 swaps), fuel and purchased energy expense (for natural gas contracts and swaps) and interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings, or until it is determined that the forecasted transaction is probable of not occurring. Upon repayment of our NDH Project Debt and other project debt, we terminated and settled the interest rate swaps related to these debt instruments and recorded $ 17 million to (gain) loss on interest rate derivatives, net for both the three months and six months ended June 30, 2011. See Note 5 for further information about the repayment of the NDH Project Debt as well as the repayment of other project debt with proceeds from our New Term Loan.
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 except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility and Other Project Debt During 2010, we repaid approximately $ 3.5 billion of our First Lien Credit Facility term loans, which had approximately $3.3 billion notional amount of interest rate swaps hedging the scheduled variable interest payments, and in January 2011, we repaid the remaining approximately $1.2 billion of First Lien Credit Facility term loans which had approximately $ 1.0 billion notional amount of interest rate swaps hedging the scheduled variable interest payments. With the repayment of the remaining First Lien Credit Facility term loans, the remaining unrealized losses of approximately $ 91 million in AOCI related to the interest swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into income as an additional (gain) loss on interest rate derivatives, net, during the first quarter of 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to (gain) loss on interest rate derivatives, net during the second quarter of 2011 resulting from the repayment of project debt in June 2011. We have presented the reclassification of unrealized losses from AOCI into income and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as (gain) loss on interest rate derivatives, net on our Consolidated Condensed Statements of Operations. We also have determined that, based upon current market conditions and consistent with our risk management policy, liquidation of these interest rate swaps is not economically beneficial and additional future losses are limited. Accordingly, we have elected to retain and hold these interest rate swap positions at this time.
Consolidation of VIEs
We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly impact the VIEs economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined 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 determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant impact on a power plants financial performance: operations and maintenance, plant dispatch, and 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 is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
evaluate if an entity is a VIE and whether we are the primary beneficiary whenever 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 VIEs economic performance.
|
|
|
|
| ||
Consideration |
| $ | 1,640 |
| |
|
|
|
|
| |
Final values of identifiable assets acquired and liabilities assumed: |
|
|
|
| |
Assets: |
|
|
|
| |
Current assets |
| $ | 78 |
| |
Property, plant and equipment, net |
|
| 1,574 |
| |
Other long-term assets |
|
| 85 |
| |
Total assets acquired |
|
| 1,737 |
| |
Liabilities: |
|
|
|
| |
Current liabilities |
|
| 46 |
| |
Long-term liabilities |
|
| 51 |
| |
Total liabilities assumed |
|
| 97 |
| |
Net assets acquired |
| $ | 1,640 |
|
|
| Three Months Ended |
|
| Six Months Ended |
| ||||
|
| June 30, 2010 |
|
| June 30, 2010 |
| ||||
Operating revenues |
| $ | 25 |
|
| $ | 50 |
| ||
Income from discontinued operations before taxes |
| $ | 12 |
|
| $ | 20 |
| ||
Less: Income tax expense |
|
| 8 |
|
|
| 8 |
| ||
Discontinued operations, net of tax |
| $ | 4 |
|
| $ | 12 |
|
|
|
| Ownership Interest as of June 30, 2011 |
|
| June 30, |
|
| December 31, |
| ||||||
Greenfield LP |
|
| 50 | % |
| $ | 79 |
|
| $ | 77 |
| |||
Whitby |
|
| 50 | % |
|
| 5 |
|
|
| 3 |
| |||
Total investments |
|
|
|
|
| $ | 84 |
|
| $ | 80 |
|
_________
(1) | 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. At June 30, 2011, and December 31, 2010, equity method investee debt was approximately $514 million and $494 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $257 million and $247 million at June 30, 2011 and December 31, 2010, respectively. |
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Greenfield LP |
| $ | 4 |
|
| $ | (3 | ) |
| $ | (1 | ) |
| $ | (7 | ) | ||||
Whitby |
|
| (2 | ) |
|
| (3 | ) |
|
| (6 | ) |
|
| (6 | ) | ||||
Total |
| $ | 2 |
|
| $ | (6 | ) |
| $ | (7 | ) |
| $ | (13 | ) |
|
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Net loss |
| $ | (70 | ) |
| $ | (114 | ) |
| $ | (366 | ) |
| $ | (162 | ) | ||||
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss |
|
| (17 | ) |
|
| (71 | ) |
|
| 14 |
|
|
| 30 |
| ||||
Reclassification adjustment for cash flow hedges realized in net loss |
|
| (31 | ) |
|
| 8 |
|
|
| 44 |
|
|
| 22 |
| ||||
Foreign currency translation loss |
|
| (1 | ) |
|
| (2 | ) |
|
| — |
|
|
| — |
| ||||
Income tax (expense) benefit |
|
| 18 |
|
|
| (23 | ) |
|
| (16 | ) |
|
| (9 | ) | ||||
Comprehensive loss |
|
| (101 | ) |
|
| (202 | ) |
|
| (324 | ) |
|
| (119 | ) | ||||
Add: Comprehensive income attributable to the noncontrolling interest |
|
| — |
|
|
| (1 | ) |
|
| (1 | ) |
|
| — |
| ||||
Comprehensive loss attributable to Calpine |
| $ | (101 | ) |
| $ | (203 | ) |
| $ | (325 | ) |
| $ | (119 | ) |
|
5. Debt
Our debt at June 30, 2011 and December 31, 2010, was as follows (in millions):
|
| June 30, |
|
| December 31, |
| ||||
First Lien Notes(1) |
| $ | 5,891 |
|
| $ | 4,691 |
| ||
Project financing, notes payable and other(2)(3) |
|
| 1,568 |
|
|
| 1,922 |
| ||
Term Loan and New Term Loan(2)(4) |
|
| 1,654 |
|
|
| — |
| ||
NDH Project Debt(4) |
|
| — |
|
|
| 1,258 |
| ||
First Lien Credit Facility(1) |
|
| — |
|
|
| 1,184 |
| ||
CCFC Notes |
|
| 969 |
|
|
| 965 |
| ||
Capital lease obligations |
|
| 234 |
|
|
| 236 |
| ||
Total debt |
|
| 10,316 |
|
|
| 10,256 |
| ||
Less: Current maturities |
|
| 126 |
|
|
| 152 |
| ||
Debt, net of current portion |
| $ | 10,190 |
|
| $ | 10,104 |
|
_________
(1) | On January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed below. |
(2) | On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described below. |
(3) | On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City as further described below. |
(4) | On March 9, 2011, we borrowed $1.3 billion under the Term Loan and repaid and terminated the NDH Project Debt as discussed below. |
|
| June 30, |
|
| December 31, |
| ||||
2017 First Lien Notes |
| $ | 1,200 |
|
| $ | 1,200 |
| ||
2019 First Lien Notes |
|
| 400 |
|
|
| 400 |
| ||
2020 First Lien Notes |
|
| 1,091 |
|
|
| 1,091 |
| ||
2021 First Lien Notes |
|
| 2,000 |
|
|
| 2,000 |
| ||
2023 First Lien Notes(1) |
|
| 1,200 |
|
|
| — |
| ||
Total First Lien Notes |
| $ | 5,891 |
|
| $ | 4,691 |
|
_________
(1) | On January 14, 2011, we issued $1.2 billion in aggregate principal amount of 7.875% senior secured notes due 2023 in a private placement. The 2023 First Lien Notes bear interest at 7.875% payable semi-annually on January 15 and July 15 of each year, beginning on July 15, 2011. The 2023 First Lien Notes will mature on January 15, 2023. |
|
| June 30, |
|
| December 31, |
| ||||
Corporate Revolving Facility(1) |
| $ | 369 |
|
| $ | 443 |
| ||
Calpine Development Holdings, Inc. |
|
| 193 |
|
|
| 165 |
| ||
NDH Project Debt credit facility(2) |
|
| — |
|
|
| 34 |
| ||
Various project financing facilities |
|
| 100 |
|
|
| 69 |
| ||
Total |
| $ | 662 |
|
| $ | 711 |
|
_________
(1) | When we entered into our $1.0 billion Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced with letters of credit issued by our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third-party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. |
(2) | We repaid and terminated the NDH Project Debt on March 9, 2011. |
|
| June 30, 2011 |
|
| December 31, 2010 |
| ||||||||||||||
|
| Fair Value |
|
| Carrying Value |
|
| Fair Value |
|
| Carrying Value |
| ||||||||
First Lien Notes(1) |
| $ | 6,032 |
|
| $ | 5,891 |
|
| $ | 4,695 |
|
| $ | 4,691 |
| ||||
Project financing, notes payable and other(2)(3)(4) |
|
| 1,355 |
|
|
| 1,378 |
|
|
| 1,673 |
|
|
| 1,708 |
| ||||
Term Loan and New Term Loan(1)(2) |
|
| 1,638 |
|
|
| 1,654 |
|
|
| — |
|
|
| — |
| ||||
NDH Project Debt(1) |
|
| — |
|
|
| — |
|
|
| 1,303 |
|
|
| 1,258 |
| ||||
First Lien Credit Facility(1) |
|
| — |
|
|
| — |
|
|
| 1,182 |
|
|
| 1,184 |
| ||||
CCFC Notes |
|
| 1,073 |
|
|
| 969 |
|
|
| 1,067 |
|
|
| 965 |
| ||||
Total |
| $ | 10,098 |
|
| $ | 9,892 |
|
| $ | 9,920 |
|
| $ | 9,806 |
|
_________
(1) | On March 9, 2011, we repaid and terminated the NDH Project Debt with proceeds received from the Term Loan, and on January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed above. |
(2) | On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as described above. |
(3) | On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City as described above. |
(4) | 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. |
|
|
| Assets and Liabilities with Recurring Fair Value Measures |
| |||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
|
| (in millions) |
| |||||||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash equivalents(1) |
| $ | 1,334 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,334 |
| ||||
Margin deposits |
|
| 133 |
|
|
| — |
|
|
| — |
|
|
| 133 |
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
|
| 460 |
|
|
| — |
|
|
| — |
|
|
| 460 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 173 |
|
|
| 45 |
|
|
| 218 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
| ||||
Total assets |
| $ | 1,927 |
|
| $ | 174 |
|
| $ | 45 |
|
| $ | 2,146 |
| ||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
| $ | 414 |
|
| $ | — |
|
| $ | — |
|
| $ | 414 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 112 |
|
|
| 24 |
|
|
| 136 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 314 |
|
|
| — |
|
|
| 314 |
| ||||
Total liabilities |
| $ | 414 |
|
| $ | 426 |
|
| $ | 24 |
|
| $ | 864 |
|
|
| Assets and Liabilities with Recurring Fair Value Measures |
| |||||||||||||||||
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
|
| Total |
| ||||||||
|
| (in millions) |
| |||||||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Cash equivalents(1) |
| $ | 1,297 |
|
| $ | — |
|
| $ | — |
|
| $ | 1,297 |
| ||||
Margin deposits |
|
| 162 |
|
|
| — |
|
|
| — |
|
|
| 162 |
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
|
| 550 |
|
|
| — |
|
|
| — |
|
|
| 550 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 287 |
|
|
| 54 |
|
|
| 341 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 4 |
|
|
| — |
|
|
| 4 |
| ||||
Total assets |
| $ | 2,009 |
|
| $ | 291 |
|
| $ | 54 |
|
| $ | 2,354 |
| ||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Margin deposits held by us posted by our counterparties |
| $ | 6 |
|
| $ | — |
|
| $ | — |
|
| $ | 6 |
| ||||
Commodity instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Commodity futures contracts |
|
| 574 |
|
|
| — |
|
|
| — |
|
|
| 574 |
| ||||
Commodity forward contracts(2) |
|
| — |
|
|
| 119 |
|
|
| 24 |
|
|
| 143 |
| ||||
Interest rate swaps |
|
| — |
|
|
| 371 |
|
|
| — |
|
|
| 371 |
| ||||
Total liabilities |
| $ | 580 |
|
| $ | 490 |
|
| $ | 24 |
|
| $ | 1,094 |
|
_________
(1) | At June 30, 2011, and December 31, 2010, we had cash equivalents of $1,144 million and $1,094 million included in cash and cash equivalents and $190 million and $203 million included in restricted cash, respectively. |
(2) | Includes OTC swaps and options. |
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Balance, beginning of period |
| $ | 12 |
|
| $ | 57 |
|
| $ | 30 |
|
| $ | 38 |
| ||||
Realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Included in net loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Included in operating revenues(1) |
|
| 10 |
|
|
| 10 |
|
|
| 6 |
|
|
| 29 |
| ||||
Included in fuel and purchased energy expense(2) |
|
| 1 |
|
|
| (3 | ) |
|
| — |
|
|
| (3 | ) | ||||
Included in OCI |
|
| 4 |
|
|
| (5 | ) |
|
| 5 |
|
|
| — |
| ||||
Purchases, issuances, sales and settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Purchases |
|
| 1 |
|
|
| — |
|
|
| 1 |
|
|
| — |
| ||||
Settlements |
|
| (7 | ) |
|
| (16 | ) |
|
| (21 | ) |
|
| (22 | ) | ||||
Transfers into and/or out of level 3:(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Transfers out of level 3(4) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
| ||||
Balance, end of period |
| $ | 21 |
|
| $ | 43 |
|
| $ | 21 |
|
| $ | 43 |
| ||||
Change in unrealized gains relating to instruments held at end of period |
| $ | 11 |
|
| $ | 7 |
|
| $ | 7 |
|
| $ | 26 |
|
_________
(1) | For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations. |
(2) | For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. |
(3) | We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no significant transfers into/out of level 1 or out of level 2 or into level 3 during the three and six months ended June 30, 2011 and 2010. |
(4) | There were no significant transfers into level 2 or out of level 3 for the three months ended June 30, 2011 and 2010, and the six months ended June 30, 2011. We had $(1) million in losses transferred out of level 3 into level 2 for the six months ended June 30, 2010. Transfers out of level 3 into level 2 were due to changes in market liquidity in various power markets. |
|
|
| Notional Amounts |
| |||||||
|
| June 30, |
|
| December 31, |
| ||||
Derivative Instruments |
|
|
|
|
|
|
|
| ||
Power (MWh) |
|
| (40 | ) |
|
| (50 | ) | ||
Natural gas (MMBtu) |
|
| 170 |
|
|
| 31 |
| ||
Interest rate swaps(1) |
| $ | 5,191 |
|
| $ | 6,171 |
|
_________
(1) | Approximately $4.1 billion and $3.3 billion at June 30, 2011 and December 31, 2010, respectively, related to variable rate debt that was converted to fixed rate debt in 2011 and 2010. |
|
| June 30, 2011 |
| ||||||||||||
|
| Interest Rate |
|
| Commodity |
|
| Total Derivative |
| ||||||
Balance Sheet Presentation |
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative assets |
| $ | — |
|
| $ | 569 |
|
| $ | 569 |
| |||
Long-term derivative assets |
|
| 1 |
|
|
| 109 |
|
|
| 110 |
| |||
Total derivative assets |
| $ | 1 |
|
| $ | 678 |
|
| $ | 679 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative liabilities |
| $ | 195 |
|
| $ | 448 |
|
| $ | 643 |
| |||
Long-term derivative liabilities |
|
| 119 |
|
|
| 102 |
|
|
| 221 |
| |||
Total derivative liabilities |
| $ | 314 |
|
| $ | 550 |
|
| $ | 864 |
| |||
Net derivative assets (liabilities) |
| $ | (313 | ) |
| $ | 128 |
|
| $ | (185 | ) |
|
| December 31, 2010 |
| ||||||||||||
|
| Interest Rate |
|
| Commodity |
|
| Total Derivative |
| ||||||
Balance Sheet Presentation |
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative assets |
| $ | — |
|
| $ | 725 |
|
| $ | 725 |
| |||
Long-term derivative assets |
|
| 4 |
|
|
| 166 |
|
|
| 170 |
| |||
Total derivative assets |
| $ | 4 |
|
| $ | 891 |
|
| $ | 895 |
| |||
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Current derivative liabilities |
| $ | 197 |
|
| $ | 521 |
|
| $ | 718 |
| |||
Long-term derivative liabilities |
|
| 174 |
|
|
| 196 |
|
|
| 370 |
| |||
Total derivative liabilities |
| $ | 371 |
|
| $ | 717 |
|
| $ | 1,088 |
| |||
Net derivative assets (liabilities) |
| $ | (367 | ) |
| $ | 174 |
|
| $ | (193 | ) |
|
| June 30, 2011 |
|
| December 31, 2010 |
| ||||||||||||||
|
| Fair Value of |
|
| Fair Value of |
|
| Fair Value of |
|
| Fair Value of |
| ||||||||
Derivatives designated as cash flow hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | — |
|
| $ | 49 |
|
| $ | 2 |
|
| $ | 143 |
| ||||
Commodity instruments |
|
| 104 |
|
|
| 41 |
|
|
| 161 |
|
|
| 52 |
| ||||
Total derivatives designated as cash flow hedging instruments |
| $ | 104 |
|
| $ | 90 |
|
| $ | 163 |
|
| $ | 195 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Derivatives not designated as hedging instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | 1 |
|
| $ | 265 |
|
| $ | 2 |
|
| $ | 228 |
| ||||
Commodity instruments |
|
| 574 |
|
|
| 509 |
|
|
| 730 |
|
|
| 665 |
| ||||
Total derivatives not designated as hedging instruments |
| $ | 575 |
|
| $ | 774 |
|
| $ | 732 |
|
| $ | 893 |
| ||||
Total derivatives |
| $ | 679 |
|
| $ | 864 |
|
| $ | 895 |
|
| $ | 1,088 |
|
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Realized gain (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | (60 | ) |
| $ | (6 | ) |
| $ | (106 | ) |
| $ | (12 | ) | ||||
Commodity derivative instruments |
|
| 42 |
|
|
| 59 |
|
|
| 52 |
|
|
| 52 |
| ||||
Total realized gain (loss) |
| $ | (18 | ) |
| $ | 53 |
|
| $ | (54 | ) |
| $ | 40 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Unrealized gain (loss)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Interest rate swaps |
| $ | 24 |
|
| $ | (16 | ) |
| $ | (38 | ) |
| $ | (19 | ) | ||||
Commodity derivative instruments |
|
| 26 |
|
|
| (31 | ) |
|
| (39 | ) |
|
| 81 |
| ||||
Total unrealized gain (loss) |
| $ | 50 |
|
| $ | (47 | ) |
| $ | (77 | ) |
| $ | 62 |
| ||||
Total mark-to-market activity |
| $ | 32 |
|
| $ | 6 |
|
| $ | (131 | ) |
| $ | 102 |
|
_________
(1) | Changes in unrealized gain (loss) include de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Realized and unrealized gain (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Power contracts included in operating revenues |
| $ | 48 |
|
| $ | 41 |
|
| $ | (9 | ) |
| $ | 12 |
| ||||
Natural gas contracts included in fuel and purchased energy expense |
|
| 20 |
|
|
| (13 | ) |
|
| 22 |
|
|
| 121 |
| ||||
Interest rate swaps included in interest expense |
|
| 1 |
|
|
| (30 | ) |
|
| 2 |
|
|
| (28 | ) | ||||
Gain (loss) on interest rate derivatives, net |
|
| (37 | ) |
|
| 8 |
|
|
| (146 | ) |
|
| (3 | ) | ||||
Total mark-to-market activity |
| $ | 32 |
|
| $ | 6 |
|
| $ | (131 | ) |
| $ | 102 |
|
|
| Three Months Ended June 30, |
| |||||||||||||||||||||||||||
|
| Gain (Loss) Recognized in OCI (Effective Portion) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Effective Portion)(2) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Ineffective Portion) |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Interest rate swaps |
| $ | (9 | ) |
| $ | (16 | ) |
| $ | (22 | ) |
| $ | (62 | ) |
| $ | (1 | ) |
| $ | — |
| ||||||
Commodity derivative instruments |
|
| (39 | ) |
|
| (47 | ) |
|
| 53 |
|
|
| 54 |
|
|
| 1 |
|
|
| 3 |
| ||||||
Total |
| $ | (48 | ) |
| $ | (63 | ) |
| $ | 31 |
|
| $ | (8 | ) |
| $ | — |
|
| $ | 3 |
|
|
| Six Months Ended June 30, |
| |||||||||||||||||||||||||||
|
| Gain (Loss) Recognized in OCI (Effective Portion) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Effective Portion)(2) |
|
| Gain (Loss) Reclassified from AOCI Into Income (Ineffective Portion) |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Interest rate swaps |
| $ | 94 |
|
| $ | (27 | ) |
| $ | (123 | )(4) |
| $ | (122 | ) |
| $ | (1 | ) |
| $ | — |
| ||||||
Commodity derivative instruments |
|
| (36 | ) |
|
| 79 |
|
|
| 79 | (1) |
|
| 100 |
|
|
| 1 |
|
|
| 1 |
| ||||||
Total |
| $ | 58 |
|
| $ | 52 |
|
| $ | (44 | ) |
| $ | (22 | ) |
| $ | — |
|
| $ | 1 |
|
_________
(1) | Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations. |
(2) | Cumulative cash flow hedge losses remaining in AOCI were $81 million and $122 million at June 30, 2011 and December 31, 2010, respectively. |
(3) | Reclassification of losses from OCI to earnings for the three months ended June 30, 2011 consisted of $7 million in losses from the reclassification of interest rate contracts due to settlement and $15 million in losses from terminated interest rate contracts due to the repayment of project debt in June 2011. |
(4) | Reclassification of losses from OCI to earnings for the six months ended June 30, 2011 consisted of $17 million in losses from the reclassification of interest rate contracts due to settlement, $15 million in losses from terminated interest rate contracts due to the repayment of project debt in June 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinance of variable rate First Lien Credit Facility term loans. |
|
|
| June 30, |
|
| December 31, |
| ||||
Margin deposits(1) |
| $ | 133 |
|
| $ | 162 |
| ||
Natural gas and power prepayments |
|
| 49 |
|
|
| 43 |
| ||
Total margin deposits and natural gas and power prepayments with our counterparties(2) |
| $ | 182 |
|
| $ | 205 |
| ||
|
|
|
|
|
|
|
|
| ||
Letters of credit issued(3) |
| $ | 492 |
|
| $ | 588 |
| ||
First priority liens under power and natural gas agreements(4) |
|
| — |
|
|
| — |
| ||
First priority liens under interest rate swap agreements |
|
| 299 |
|
|
| 356 |
| ||
Total letters of credit and first priority liens with our counterparties |
| $ | 791 |
|
| $ | 944 |
| ||
|
|
|
|
|
|
|
|
| ||
Margin deposits held by us posted by our counterparties(1)(5) |
| $ | — |
|
| $ | 6 |
| ||
Letters of credit posted with us by our counterparties |
|
| 36 |
|
|
| 66 |
| ||
Total margin deposits and letters of credit posted with us by our counterparties |
| $ | 36 |
|
| $ | 72 |
|
_________
(1) | Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation. |
(2) | At June 30, 2011 and December 31, 2010, $158 million and $183 million were included in margin deposits and other prepaid expense, respectively, and $24 million and $22 million were included in other assets at June 30, 2011 and December 31, 2010, respectively, on our Consolidated Condensed Balance Sheets. |
(3) | When we entered into our Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit issued under our Corporate Revolving Facility used for our commodity procurement and risk management activities at December 31, 2010 include those that were back-stopped of approximately $63 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. |
(4) | At June 30, 2011, and December 31, 2010, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $99 million and $193 million, respectively; therefore, there was no collateral exposure at June 30, 2011, or December 31, 2010. |
(5) | Included in other current liabilities on our Consolidated Condensed Balance Sheets. |
|
|
| Three Months Ended June 30, |
|
| Six Months Ended June 30, |
| ||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||
Income tax expense (benefit) |
| $ | 18 |
|
| $ | 6 |
|
| $ | (65 | )(1) |
| $ | 17 | (2) | ||||
Imputed tax rate |
|
| (35 | )% |
|
| (5 | )% |
|
| 15 | % |
|
| (11 | )% | ||||
Intraperiod tax allocation expense (benefit) |
| $ | 18 |
|
| $ | (31 | ) |
| $ | (16 | ) |
| $ | (17 | ) |
_________
(1) | Includes a tax benefit of approximately $76 million related to the consolidation of the CCFC and Calpine groups for federal income tax reporting purposes for the six months ended June 30, 2011 (as described below). |
(2) | Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI. |
|
| Six Months Ended June 30, |
| |||||||||||||||||||||||||||
|
| Included in continuing |
|
| Included in discontinued operations |
|
| Included in OCI |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Intraperiod tax allocations expense (benefit) |
| $ | (16 | ) |
| $ | (17 | ) |
| $ | — |
|
| $ | 8 |
|
| $ | 16 |
|
| $ | 9 |
|
Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) and income from discontinued operations with an offsetting amount recognized in OCI and discontinued operations. The following table details the effects of our intraperiod tax allocations for the three and six months ended June 30, 2011 and 2010 (in millions).
|
| Three Months Ended June 30, |
| |||||||||||||||||||||||||||
|
| Included in continuing |
|
| Included in discontinued operations |
|
| Included in OCI |
| |||||||||||||||||||||
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
|
| 2011 |
|
| 2010 |
| ||||||||||||
Intraperiod tax allocation expense (benefit) |
| $ | 18 |
|
| $ | (31 | ) |
| $ | — |
|
| $ | 8 |
|
| $ | (18 | ) |
| $ | 23 |
|
|
|
| Number of Shares |
|
| Weighted Average Exercise Price |
|
| Weighted Average Remaining Term |
|
| Aggregate Intrinsic Value |
| ||||||||
Outstanding - December 31, 2010 |
|
| 17,164,890 |
|
| $ | 17.44 |
|
|
| 5.6 |
|
| $ | 8 |
| ||||
Granted |
|
| 909,306 |
|
| $ | 14.32 |
|
|
|
|
|
|
|
|
| ||||
Exercised |
|
| 6,654 |
|
| $ | 10.95 |
|
|
|
|
|
|
|
|
| ||||
Forfeited |
|
| 51,050 |
|
| $ | 11.23 |
|
|
|
|
|
|
|
|
| ||||
Expired |
|
| 156,885 |
|
| $ | 17.55 |
|
|
|
|
|
|
|
|
| ||||
Outstanding - June 30, 2011 |
|
| 17,859,607 |
|
| $ | 17.30 |
|
|
| 5.3 |
|
| $ | 25 |
| ||||
Exercisable - June 30, 2011 |
|
| 6,665,499 |
|
| $ | 19.15 |
|
|
| 5.3 |
|
| $ | 1 |
| ||||
Vested and expected to vest - June 30, 2011 |
|
| 17,443,021 |
|
| $ | 17.41 |
|
|
| 5.2 |
|
| $ | 24 |
|
|
| 2011 |
|
| 2010 |
| ||||
Expected term (in years)(1) |
|
| 6.5 |
|
|
| 6.5 |
| ||
Risk-free interest rate(2) |
|
| 2.7 — 3.2 | % |
|
| 2.9 — 3.3 | % | ||
Expected volatility(3) |
|
| 31.2 — 31.7 | % |
|
| 35.0 — 37.6 | % | ||
Dividend yield(4) |
|
| — |
|
|
| — |
| ||
Weighted average grant-date fair value (per option) |
| $ | 5.48 |
|
| $ | 4.66 |
|
_________
(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 have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future. |
|
| Number of |
|
| Weighted |
| ||||
Nonvested - December 31, 2010 |
|
| 2,683,117 |
|
| $ | 11.16 |
| ||
Granted |
|
| 1,630,465 |
|
| $ | 14.38 |
| ||
Forfeited |
|
| 145,923 |
|
| $ | 11.88 |
| ||
Vested |
|
| 460,232 |
|
| $ | 14.62 |
| ||
Nonvested - June 30, 2011 |
|
| 3,707,427 |
|
| $ | 12.10 |
|
|
|
| Three Months Ended June 30, 2011 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 466 |
|
| $ | 646 |
|
| $ | 324 |
|
| $ | 197 |
|
| $ | — |
|
| $ | 1,633 |
| ||||||
Intersegment revenues |
|
| 1 |
|
|
| 5 |
|
|
| 5 |
|
|
| 40 |
|
|
| (51 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 467 |
|
| $ | 651 |
|
| $ | 329 |
|
| $ | 237 |
|
| $ | (51 | ) |
| $ | 1,633 |
| ||||||
Commodity Margin |
| $ | 236 |
|
| $ | 128 |
|
| $ | 179 |
|
| $ | 59 |
|
| $ | — |
|
| $ | 602 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 11 |
|
|
| 27 |
|
|
| — |
|
|
| — |
|
|
| (9 | ) |
|
| 29 |
| ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 116 |
|
|
| 63 |
|
|
| 47 |
|
|
| 41 |
|
|
| (6 | ) |
|
| 261 |
| ||||||
Depreciation and amortization expense |
|
| 42 |
|
|
| 35 |
|
|
| 33 |
|
|
| 22 |
|
|
| (1 | ) |
|
| 131 |
| ||||||
Sales, general and other administrative expense |
|
| 8 |
|
|
| 13 |
|
|
| 6 |
|
|
| 6 |
|
|
| 1 |
|
|
| 34 |
| ||||||
Other operating expenses(2) |
|
| 11 |
|
|
| 3 |
|
|
| 9 |
|
|
| 2 |
|
|
| (5 | ) |
|
| 20 |
| ||||||
Loss from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| 2 |
| ||||||
Income (loss) from operations |
|
| 70 |
|
|
| 41 |
|
|
| 82 |
|
|
| (12 | ) |
|
| 2 |
|
|
| 183 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 190 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 37 |
| ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 8 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (52 | ) |
|
| Three Months Ended June 30, 2010 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 525 |
|
| $ | 552 |
|
| $ | 134 |
|
| $ | 219 |
|
| $ | — |
|
| $ | 1,430 |
| ||||||
Intersegment revenues |
|
| 1 |
|
|
| 6 |
|
|
| 1 |
|
|
| 21 |
|
|
| (29 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 526 |
|
| $ | 558 |
|
| $ | 135 |
|
| $ | 240 |
|
| $ | (29 | ) |
| $ | 1,430 |
| ||||||
Commodity Margin |
| $ | 258 |
|
| $ | 128 |
|
| $ | 79 |
|
| $ | 68 |
|
| $ | — |
|
| $ | 533 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 10 |
|
|
| (10 | ) |
|
| 3 |
|
|
| (9 | ) |
|
| (6 | ) |
|
| (12 | ) | ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 88 |
|
|
| 78 |
|
|
| 23 |
|
|
| 31 |
|
|
| (7 | ) |
|
| 213 |
| ||||||
Depreciation and amortization expense |
|
| 50 |
|
|
| 40 |
|
|
| 19 |
|
|
| 27 |
|
|
| (1 | ) |
|
| 135 |
| ||||||
Sales, general and other administrative expense |
|
| 11 |
|
|
| 16 |
|
|
| 22 |
|
|
| 2 |
|
|
| (1 | ) |
|
| 50 |
| ||||||
Other operating expenses(2) |
|
| 12 |
|
|
| (5 | ) |
|
| 7 |
|
|
| (1 | ) |
|
| 8 |
|
|
| 21 |
| ||||||
(Income) from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| (6 | ) |
|
| — |
|
|
| — |
|
|
| (6 | ) | ||||||
Income (loss) from operations |
|
| 107 |
|
|
| (11 | ) |
|
| 17 |
|
|
| — |
|
|
| (5 | ) |
|
| 108 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 220 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (8 | ) | ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 8 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (112 | ) |
|
| Six Months Ended June 30, 2011 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 1,065 |
|
| $ | 1,096 |
|
| $ | 595 |
|
| $ | 376 |
|
| $ | — |
|
| $ | 3,132 |
| ||||||
Intersegment revenues |
|
| 4 |
|
|
| 10 |
|
|
| 13 |
|
|
| 85 |
|
|
| (112 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 1,069 |
|
| $ | 1,106 |
|
| $ | 608 |
|
| $ | 461 |
|
| $ | (112 | ) |
| $ | 3,132 |
| ||||||
Commodity Margin |
| $ | 469 |
|
| $ | 195 |
|
| $ | 314 |
|
| $ | 113 |
|
| $ | — |
|
| $ | 1,091 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 16 |
|
|
| (33 | ) |
|
| 4 |
|
|
| (4 | ) |
|
| (15 | ) |
|
| (32 | ) | ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 203 |
|
|
| 143 |
|
|
| 92 |
|
|
| 74 |
|
|
| (13 | ) |
|
| 499 |
| ||||||
Depreciation and amortization expense |
|
| 88 |
|
|
| 65 |
|
|
| 66 |
|
|
| 45 |
|
|
| (2 | ) |
|
| 262 |
| ||||||
Sales, general and other administrative expense |
|
| 19 |
|
|
| 23 |
|
|
| 12 |
|
|
| 11 |
|
|
| 1 |
|
|
| 66 |
| ||||||
Other operating expenses(2) |
|
| 19 |
|
|
| 3 |
|
|
| 16 |
|
|
| 3 |
|
|
| (3 | ) |
|
| 38 |
| ||||||
(Income) from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| (7 | ) |
|
| — |
|
|
| — |
|
|
| (7 | ) | ||||||
Income (loss) from operations |
|
| 156 |
|
|
| (72 | ) |
|
| 139 |
|
|
| (24 | ) |
|
| 2 |
|
|
| 201 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 378 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 146 |
| ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 108 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (431 | ) |
|
| Six Months Ended June 30, 2010 |
| |||||||||||||||||||||||||||
|
| West |
|
| Texas |
|
| North |
|
| Southeast |
|
| Consolidation |
|
| Total |
| ||||||||||||
Revenues from external customers |
| $ | 1,190 |
|
| $ | 1,079 |
|
| $ | 257 |
|
| $ | 418 |
|
| $ | — |
|
| $ | 2,944 |
| ||||||
Intersegment revenues |
|
| 5 |
|
|
| 10 |
|
|
| 2 |
|
|
| 44 |
|
|
| (61 | ) |
|
| — |
| ||||||
Total operating revenues |
| $ | 1,195 |
|
| $ | 1,089 |
|
| $ | 259 |
|
| $ | 462 |
|
| $ | (61 | ) |
| $ | 2,944 |
| ||||||
Commodity Margin |
| $ | 471 |
|
| $ | 235 |
|
| $ | 131 |
|
| $ | 126 |
|
| $ | — |
|
| $ | 963 |
| ||||||
Add: Mark-to-market commodity activity, net and other revenue(1) |
|
| 18 |
|
|
| 86 |
|
|
| — |
|
|
| 13 |
|
|
| (14 | ) |
|
| 103 |
| ||||||
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Plant operating expense |
|
| 178 |
|
|
| 162 |
|
|
| 45 |
|
|
| 59 |
|
|
| (13 | ) |
|
| 431 |
| ||||||
Depreciation and amortization expense |
|
| 103 |
|
|
| 76 |
|
|
| 39 |
|
|
| 56 |
|
|
| (3 | ) |
|
| 271 |
| ||||||
Sales, general and other administrative expense |
|
| 26 |
|
|
| 16 |
|
|
| 25 |
|
|
| 6 |
|
|
| (1 | ) |
|
| 72 |
| ||||||
Other operating expenses(2) |
|
| 29 |
|
|
| 2 |
|
|
| 15 |
|
|
| 2 |
|
|
| (1 | ) |
|
| 47 |
| ||||||
(Income) from unconsolidated investments in power plants |
|
| — |
|
|
| — |
|
|
| (13 | ) |
|
| — |
|
|
| — |
|
|
| (13 | ) | ||||||
Income from operations |
|
| 153 |
|
|
| 65 |
|
|
| 20 |
|
|
| 16 |
|
|
| 4 |
|
|
| 258 |
| ||||||
Interest expense, net of interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 399 |
| ||||||
(Gain) loss on interest rate derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 3 |
| ||||||
Debt extinguishment costs and other (income) expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 13 |
| ||||||
Loss before income taxes and discontinued operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (157 | ) |
_________
(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 $2 million and $5 million of RGGI compliance and other environmental costs for the three months ended June 30, 2011 and 2010, respectively, and $4 million and $5 million for the six months ended June 30, 2011 and 2010, respectively, which are included as a component of Commodity Margin. |
|
|
|
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