Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business and to meet certain near-term debt repayment obligations is dependent on maintaining sufficient liquidity.
| (1) | Includes $1 million and $169 million of margin deposits held by us posted by our counterparties as of September 30, 2009, and December 31, 2008, respectively. |
| (2) | Includes available balances for Calpine Development Holdings, Inc. |
| (3) | Excludes contingent amounts of $150 million under the Knock-in Facility and $200 million under the Commodity Collateral Revolver as of December 31, 2008. |
Volatility in the financial markets through 2008 and into 2009, including the failure or merger of certain financial institutions and continued uncertainty surrounding many others continues to constrict access to capital and credit markets in the U.S. and worldwide, including within our industry, for us and for our counterparties. We are unable to predict the length or severity of the economic downturn; but expect these conditions will persist during 2009 and possibly longer. As a result, we and the industry have experienced increased credit and liquidity risk over the past several months. Even if we are not impacted directly, we could be impacted indirectly in the event our counterparties are unable to perform under their contractual obligations with us. We actively monitor our exposure to our counterparties including their credit status.
Additionally, we could potentially face downward pressure on our Commodity Margin as a result of the current economic recession. The impacts would be highly dependent on the severity and duration of the economic downturn. During pronounced recessionary periods, there can be a decrease in power demand primarily driven by decreased usage by the industrial and manufacturing sectors. This “softening” of demand typically results in more demand satisfied by baseload and intermediate units using lower variable cost fuel sources such as coal and nuclear fuel, and less demand served by higher variable cost units such as natural gas-fired peaking power plants. Additionally, a recessionary environment can result in lower natural gas pricing which may adversely impact our Commodity Margin as our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis. However, with our combined forward power sales and natural gas purchases, we believe that we have economically hedged a substantial portion of our Commodity Margin for the remainder of 2009. Additionally, we have economically hedged much of 2010 and therefore do not expect further declines in natural gas prices to result in a material detriment to our results of operations in the near term.
It is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations should financial market and commodity price volatility persist for a significant period of time. Our ability to generate sufficient cash is dependent upon, among other things:
| | • | improving the profitability of our operations; |
| | • | continued compliance with the covenants under our First Lien Credit Facility, First Lien Notes and other existing financing obligations; |
| | • | stabilizing and increasing future contractual cash flows; and |
| | • | our significant counterparties performing under their contracts with us. |
Liquidity Sensitivity — Significant changes in commodity prices and Market Heat Rates can have an impact on our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of October 16, 2009, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required of approximately $150 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $146 million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Based upon historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets, we derived a statistical analysis that indicates that a change of $1/MMBtu in natural gas is comparable to a Market Heat Rate change of 170 Btu/KWh. We estimate that as of October 16, 2009, an increase of 170 Btu/KWh in the Market Heat Rate would result in an increase in collateral required of approximately $35 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $33 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above.
In order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties, we have granted additional liens on the assets currently subject to liens under the First Lien Credit Facility to collateralize our obligations under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under the First Lien Credit Facility, and certain of our interest rate swap agreements. The counterparties under such agreements will share the benefits of the collateral subject to such liens ratably with the lenders under the First Lien Credit Facility and First Lien Notes. During 2009, we have increased our usage of these additional liens in order to help manage cash collateral that would otherwise be required. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further information on our margin deposits and collateral used for commodity procurement and risk management activities.
To provide for increased liquidity in periods of rising commodity prices, we entered into the Commodity Collateral Revolver to increase our liquidity available to collateralize obligations to counterparties under eligible commodity hedge agreements during periods of increasing energy commodity prices. The Commodity Collateral Revolver provided up to a total maximum availability of $300 million contingent on mark-to-market exposure amounts under certain reference transactions. We received an initial advance of $100 million in 2008; however, on August 13, 2009, we terminated $200 million of the remaining availability under the Commodity Collateral Revolver in accordance with its terms as energy commodity prices were not expected to exceed stated thresholds in the near future and it was considered unlikely that any of the remaining $200 million availability would be available to us. The $100 million outstanding under the Commodity Collateral Revolver will mature on July 8, 2010.
We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due. Despite the current volatility in the financial markets and relative illiquidity, we were opportunistically able to amend our credit agreement to our First Lien Credit Facility and close significant financings during 2009 as further described below. If investor and creditor markets improve and more confidence returns, we may continue to refinance additional portions of our nearer term maturities or more costly debt.
Amendment of First Lien Credit Facility and Issuance of First Lien Notes due 2017 — We executed the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement dated as of August 20, 2009, which amended both the First Lien Credit Facility Credit Agreement and the First Lien Credit Facility Collateral Agency and Intercreditor Agreement. The amendment provides additional flexibility with our capital structure and First Lien Credit Facility by granting us the option, subject to certain conditions, to buy back debt at a discount using cash on hand via an auction process; to offer first lien bonds in exchange for or to retire First Lien Credit Facility term loans; to issue up to $2.0 billion of first lien bonds in lieu of issuing first lien term loans under the accordion provision of the First Lien Credit Facility; and to extend all or a portion of the revolver and term loan maturities, on revised terms, subject to acceptance by applicable lenders. In addition, the amendment provides for the aggregation of various investment and capital expenditure baskets for covenant purposes.
We subsequently issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a private placement on October 21, 2009. We received no net cash proceeds from the transaction. The offer and sale of the First Lien Notes was consummated as a permitted debt exchange pursuant to the First Lien Credit Facility in exchange for a like principal amount of First Lien Credit Facility term loans. Upon their exchange for First Lien Notes, such term loans were canceled and may not be redrawn. The First Lien Notes bear interest at 7.25% per annum payable on April 15 and October 15 of each year, beginning on April 15, 2010. The First Lien Notes will mature on October 15, 2017; however, among other things, prior to October 15, 2012, we may redeem up to 35% of the aggregate principal amount of the First Lien Notes with the net cash proceeds of certain equity offerings, at a price equal to 107.25% of the aggregate principal amount thereof, plus accrued and unpaid interest. Beginning on October 15, 2013, we may redeem all
or a portion of the First Lien Notes at a premium as defined in the indenture governing the First Lien Notes. The First Lien Notes are guaranteed by each of our current and future domestic subsidiaries that is a borrower or guarantor under our First Lien Credit Facility and the 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 the First Lien Notes. The First Lien Notes are secured equally and ratably with indebtedness under our First Lien Credit Facility by a first-priority lien, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets.
Subject to certain qualifications and exceptions, the 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 commodity hedge agreements; |
| | • | 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. |
CCFC Refinancing — On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued $1.0 billion in aggregate principal amount of CCFC New Notes in a private placement. Interest on the CCFC New Notes accrues at the rate of 8.0% per annum and is payable semi-annually in arrears on each June 1 and December 1, commencing on December 1, 2009. The CCFC New Notes, which mature on June 1, 2016, are guaranteed by two of CCFC’s subsidiaries. The CCFC New Notes and the related guarantees are secured, subject to certain exceptions and permitted liens, by all real and personal property of CCFC and CCFC’s material subsidiaries (including the CCFC Guarantors), consisting primarily of six natural gas power plants as well as the equity interests in CCFC and the CCFC Guarantors. The CCFC New Notes are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any of our other non-CCFC or CCFC Finance subsidiaries or assets. The net proceeds received of $939 million, together with CCFC cash on hand of $271 million, were used to:
| | • | repay the $364 million outstanding under the CCFC Term Loans on May 19, 2009; |
| | • | redeem the $415 million outstanding principal amount of CCFC Old Notes on June 18, 2009; |
| | • | distribute $327 million to CCFC’s indirect parent, CCFCP, which was used by CCFCP to redeem its $300 million CCFCP Preferred Shares on or before July 1, 2009; and |
| | • | in each case, pay any interest, prepayment penalties and other amounts due through the date of such repayment or redemption. |
In connection with the CCFC Refinancing, we recorded $16 million and $49 million in debt extinguishment costs for the three and nine months ended September 30, 2009, respectively. Debt extinguishment costs recorded for the three months ended September 30, 2009 related to prepayment penalties and the write-off of unamortized deferred financing costs for the CCFCP Preferred Shares that were redeemed on July 1, 2009. Debt extinguishment costs for the nine months ended September 30, 2009 are comprised of $7 million from the write-off of unamortized deferred financing costs and unamortized debt discount and $24 million of prepayment penalties related to redemption of the CCFC Old Notes, and $2 million from the write-off of unamortized deferred financing costs and unamortized debt discount and $16 million related to prepayment penalties related to the redemption of the CCFCP Preferred Shares.
We also recorded approximately $21 million in new deferred financing costs on our Consolidated Condensed Balance Sheet upon closing the CCFC Refinancing.
As a result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately $1.0 billion of debt by several years, at the same time converting it from a floating to a fixed interest rate and lowering our interest rate on such debt to 8.0% from a current weighted average interest rate of approximately 9.4% with respect to the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares.
Concurrent with the CCFC Refinancing, we replaced various intercompany agreements with our CCFC subsidiaries for the related sales and purchases of power, natural gas and the operation and maintenance of our CCFC power plants, which did not materially impact our results of operations, financial condition or cash flows on a consolidated basis.
Deer Park Financing — On January 21, 2009, Deer Park, our indirect wholly owned subsidiary, closed on $156 million of senior secured credit facilities, which include a $150 million term facility and a $6 million letter of credit facility. Proceeds received were used to settle an existing commodity contract of approximately $79 million, pay financing and legal fees of approximately $8 million and fund approximately $22 million in restricted cash. The remainder was distributed to Calpine Corporation for general corporate purposes. The senior term loan facility matures on January 21, 2012, and bears interest of LIBOR plus 3.5% or base rate plus 2.5% at Deer Park’s option.
Letter of Credit Facilities — The table below represents amounts outstanding under our letter of credit facilities as of September 30, 2009 (in millions):
| | | 2009 | |
| First Lien Credit Facility | | $ | 211 | |
| Calpine Development Holdings, Inc. | | | 148 | |
| Various project financing facilities | | | 104 | |
| Total | | $ | 463 | |
Cash Management — We manage our cash in accordance with our intercompany cash management system subject to the requirements of the First Lien Credit Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, generally exceed FDIC insured limits or are invested in money market accounts with investment banks that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be credit-worthy financial institutions and most 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.
We do not expect to pay any cash dividends on our common stock for the foreseeable future because we are currently prohibited under the First Lien Credit Facility and certain of our other debt agreements from paying cash dividends. Future cash dividends, if any, will be at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
NOLs — We have significant NOLs that will provide future tax deductions if we generate sufficient taxable income during the applicable carryover periods. Our federal and state income tax reporting group is comprised primarily of two groups, CCFC and its subsidiaries, which we refer to as the CCFC group and Calpine Corporation and its subsidiaries other than CCFC, which we refer to as the Calpine group. As of December 31, 2008, our consolidated federal NOLs totaled approximately $7.5 billion, which consists of approximately $7.1 billion from the Calpine group and approximately $396 million from the CCFC group. During 2009, the Calpine group reduced its NOLs approximately $324 million and the CCFC group increased its NOLs approximately $5 million. The changes in each group’s NOLs resulted from the cancellation of debt income resulting from the Calpine group’s emergence from Chapter 11 and adjustments to each group’s federal taxable income for 2008 and prior years as a result of the finalization and filing of their respective 2008 federal income tax returns. Accordingly, our adjusted consolidated federal NOLs at December 31, 2008 totaled approximately $7.2 billion, which consisted of approximately $6.8 billion from the Calpine group and approximately $401 million from the CCFC group. The Calpine group has recorded a valuation allowance against the deferred taxes related to most of their NOLs as we determined it is more likely than not that they will expire unutilized. Approximately $5.5 billion of our NOLs have annual limitations under Section 382 of the IRC. Subject to limitations, Section 382 amounts not used can be carried forward to succeeding years. We expect to generate approximately $90 million to $100 million in federal NOLs in 2009 from our consolidated groups. In addition, as of September 30, 2009 we have approximately $1.0 billion in foreign NOLs and $4.6 billion in state NOLs on a consolidated basis.
Optimization of Existing Assets — We continue to review development opportunities, which were put on hold during the pendency of our Chapter 11 cases, to determine whether future actions are appropriate and we may pursue new opportunities that arise, particularly if power contracts and financing are available and attractive returns are expected.
OMEC began commercial operations on October 3, 2009. The completion of OMEC added approximately 608 MW of baseload (with peaking) capacity representing our unconsolidated net interest in the power plant.
Russell City Energy Center, remains in advanced development. The Russell City Energy Center is currently contracted to deliver its full output to PG&E under a PPA, which was executed in December 2006 and approved by the CPUC in January 2007. The PPA was amended in 2008 and was approved by the CPUC on April 16, 2009. All permits for the projects have been issued and approved with the exception of an air permit now pending before the local air quality board. Completion of the Russell City Energy Center is dependent upon obtaining the necessary permits, regulatory approvals, construction contracts and construction funding under project financing facilities. We do not expect the costs to complete the Russell City Energy Center to be material to us on a consolidated basis. Upon completion, this project would bring on line approximately 362 MW of net interest baseload capacity (390 MW with peaking capacity) representing our 65% share.
We, through certain of our wholly owned subsidiaries, amended certain PPAs and entered into new PPAs with PG&E, and entered into a PPA with Southern California Edison related to certain of our power plants in California. The amended and new PPAs are all on mutually beneficial terms and many are subject to regulatory approvals and, among other things, provide for the following:
| | • | We and PG&E have agreed to an extension of the term and an increase in the volume under the existing contracts for delivery of power from our Geysers Assets. The Geysers Assets currently provide PG&E 375 MW of power under two contracts. We have agreed to increase the volume to 425 MW through 2017, and, from 2018 through the end of 2021, our Geysers Assets will supply PG&E 250 MW of renewable energy. |
| | • | Our wholly owned subsidiaries, Gilroy Energy Center, LLC, Creed Energy Center, LLC, and Goose Haven Energy Center, LLC, have entered into a replacement contract with PG&E, whereby PG&E will have greater dispatch flexibility for all 11 of our peaker power plants in California through 2017 and for seven of our peaker power plants through 2021. |
| | • | We and PG&E negotiated a new agreement to replace the existing California Department of Water Resources contract and facilitate the upgrade of our Los Esteros power plant from a 180 MW simple-cycle generation power plant to a 300 MW combined-cycle generation power plant. In addition to the increase in capacity, the upgrade will increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. While the upgrade is under construction, we will provide capacity from our Gilroy Cogeneration power plant. Upon completion of the upgrade, PG&E will purchase all of the capacity from our Los Esteros power plant for a term of ten years. |
| | • | We have entered into a new tolling arrangement with PG&E for all of the capacity from our Delta power plant beginning January 1, 2011 and ending December 31, 2013. |
| | • | We executed a resource adequacy agreement for all of the capacity from our Pastoria power plant with Southern California Edison for 2012 and 2013. |
In addition to the above, we believe that upgrades and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. We are in the process of upgrading certain of our turbines to increase our generation and efficiencies beginning in the fourth quarter of 2009 and extending through 2013 with estimated additional capital expenditures of approximately $100 million.
Cash Flow Activities — The following table summarizes our cash flow activities for the nine months ended September 30, 2009 and 2008 (in millions):
| | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | |
| Beginning cash and cash equivalents | | $ | 1,657 | | | $ | 1,915 | |
| Net cash provided by (used in): | | | | | | | | |
| Operating activities | | | 537 | | | | 355 | |
| Investing activities | | | (164 | ) | | | 534 | |
| Financing activities | | | (1,117 | ) | | | (1,953 | ) |
| Net decrease in cash and cash equivalents | | | (744 | ) | | | (1,064 | ) |
| Ending cash and cash equivalents | | $ | 913 | | | $ | 851 | |
Net Cash Provided By Operating Activities
Cash flows provided by operating activities for the nine months ended September 30, 2009, improved to $537 million compared to $355 million for the nine months ended September 30, 2008. Our improvement in cash flows provided by operating activities was primarily due to:
| | • | Interest paid — Cash paid for interest decreased by $310 million, to $563 million for the nine months ended September 30, 2009, as compared to $873 million for the same period in 2008, primarily due to the repayment of the Second Priority Debt, the one-time payments of post-petition interest of $135 million related to pre-emergence debt and $27 million in post-petition interest paid by our Canadian subsidiaries as a result of our emergence from Chapter 11 on January 31, 2008 and, to a lesser extent, lower interest rates for the comparable period in 2009. |
| | • | Reorganization costs — Cash payments for reorganization items decreased by $119 million. |
Our improvements in net cash flows provided by operating activities were partially offset by the following:
| | • | Gross profit — Gross profit, excluding unrealized changes in mark-to-market activity, depreciation expense and loss on disposal of assets, decreased by $28 million for the nine months ended September 30, 2009, as compared to the same period in 2008. This was primarily attributable to lower Commodity Margin largely due to lower natural gas prices and lower Market Heat Rates, which was partially offset by the positive impact of our hedging activities and higher Market Heat Rates in the Southeast. |
| | • | Working capital — Working capital employed increased by approximately $202 million for the 2009 period compared to the 2008 period, after adjusting for debt-related balances and derivative activities, which did not impact cash provided by operating activities. The increase was primarily due to a reduction in assets held for sale for the nine months ended September 30, 2008. |
| | • | Debt extinguishment costs — Cash payments for debt extinguishment costs in the 2009 period were $40 million related to the CCFC Refinancing, compared to cash payments of $6 million related to the refinancing of Blue Spruce and Metcalf for the comparable period in 2008. |
| | • | Cash taxes – Cash received for tax refunds was $43 million for the nine months ended September 30, 2009 compared to $78 million for the nine months ended September 30, 2008, a decrease of $35 million. The decrease in refunds was partially offset by cash paid for taxes, which was $6 million for the nine months ended September 30, 2009 compared to $16 million for the nine months ended September 30, 2008, a decrease of $10 million. |
Net Cash Provided By (Used In) Investing Activities
Cash flows used in investing activities for the nine months ended September 30, 2009, were $164 million compared to cash flows provided by investing activities of $534 million for the nine months ended September 30, 2008. The decrease in cash flows from investing activities was primarily due to:
| | • | Sale of power plants, turbines and investments — We had no significant asset sales in 2009 compared to $398 million of cash received from the sales of the Fremont and Hillabee development projects in 2008. |
| | • | Reconsolidation of the Canadian Debtors and other deconsolidated foreign entities — In 2008, we had a favorable cash effect of $64 million from the reconsolidation of the Canadian Debtors and other deconsolidated foreign entities. |
| | • | Return of investment from unconsolidated investments — For the nine months ended September 30, 2009, we received distributions of nil compared to $26 million for the nine months ended September 30, 2008. |
| | • | Capital expenditures — Net capital expenditures (capital expenditures offset by proceeds from asset disposals) increased by $48 million in 2009 resulting from our maintenance programs and environmental upgrades. |
| | • | Restricted cash requirements — Restricted cash increased $2 million in 2009, compared to a favorable $145 million decrease for the same period in 2008. |
Net Cash Used In Financing Activities
Due to our emergence from Chapter 11 during the first quarter of 2008, our financing activities are not directly comparable. Cash flows used in financing activities for the nine months ended September 30, 2009, resulted in outflows of approximately $1.1 billion compared to outflows of approximately $2.0 billion for the same period in 2008. Our significant 2009 and 2008 financing transactions are described below:
| | • | During the nine months ended September 30, 2009, we had net cash borrowings of approximately $1.0 billion from the issuance of the CCFC New Notes and from the refinancing of Deer Park, and we repaid $725 million previously drawn under our First Lien Credit Facility revolver, $779 million of CCFC Old Notes and CCFC Term Loans and $300 million of CCFC Preferred Shares. We also made scheduled repayments of approximately $45 million under the First Lien Credit Facility term loans and $260 million on notes payable, other project debt and capital lease obligations. |
| | • | During the 2008 period, we borrowed approximately $3.6 billion under our First Lien Facilities and used that borrowing and cash on hand to repay approximately $3.7 billion of the Second Priority Debt, $1.1 billion on the First Lien Credit Facility revolver, $300 million on the Bridge Facility, and $128 million of First Lien Credit Facility term loans under our First Lien Facilities. In addition, we received proceeds of $355 million from refinancing Metcalf and Blue Spruce and repaid $567 million of other project financing, capital leases and notes payable. |
| | • | We incurred finance costs of $34 million in 2009 to facilitate an amendment to our First Lien Credit Facility and for the CCFC and Deer Park refinancings. During the nine months ended September 30, 2008, we incurred $207 million of financing costs primarily related to the closing on our First Lien Facilities. |
| | • | We received $70 million from the settlement of derivatives with an other-than-insignificant financing element for the nine months ended September 30, 2008. |
Special Purpose Subsidiaries — Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities. As of the date of filing this Report, these entities included: Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, Power Contract Financing , L.L.C., Power Contract Financing III, LLC, GEC Holdings, LLC, Gilroy Energy Center, LLC, Creed Energy Center, LLC, Goose Haven Energy Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), CCFCP, and Russell City Energy Company, LLC.
We actively seek to manage the commodity risks of our portfolio, utilizing multiple strategies of buying and selling power or natural gas to manage our spark spread, or selling Heat Rate transactions.
We utilize derivatives, which include physical commodity contracts and financial commodity instruments such as swaps, options and NYMEX contracts to manage commodity price risk and to maximize the risk-adjusted returns from our power and natural gas assets. We conduct these hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk measurement and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin.
Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often act as hedges to our asset portfolio, but do not qualify as hedges under hedge accounting guidelines, such as commodity options transactions and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options). While our selling and purchasing of power and natural gas is mostly physical in nature, we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in nature. While we enter into these transactions primarily to provide us with improved price and price volatility transparency, as well as greater market access, which benefits our hedging activities, we also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings in mark-to-market activity within operating revenues in the case of power transactions, and within fuel and purchased energy expense, in the case of natural gas transactions. Our future hedged status, and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, Risk Management Committee of senior management and Board of Directors.
We have economically hedged a substantial portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for the remainder of 2009 and much of 2010. By entering into these transactions, we are able to economically hedge a portion of our spark spread at pre-determined generation and price levels. We utilize a combination of PPAs and other hedging instruments to manage our variability in future cash flows. As of September 30, 2009, the maximum length of our PPAs extends 24 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 3 and 17 years, respectively. Assuming constant September 30, 2009, power and natural gas prices and interest rates, we estimate that pre-tax net losses of $46 million would be reclassified from AOCI into earnings during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will vary based on changes in natural gas and power prices as well as interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI to earnings (positive or negative) will be for the next 12 months.
Derivatives — We enter into a variety of derivative instruments such as exchange traded and OTC power and natural gas futures, forwards, options, fixed for floating swaps, instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. Derivative contracts are measured at their fair value and recorded as either assets or liabilities unless they qualify for and we elect the normal purchase or normal sale exemption. All changes in the fair value of contracts accounted for as derivatives are recognized currently in earnings (as a component of our operating revenues, fuel and purchased energy expense, or interest expense) unless specific hedge criteria are met. The hedge criteria require us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The actual amounts that will ultimately be settled will likely vary based on changes in natural gas prices and power prices as well as changes in interest rates. Such variances could be material.
The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu and MWh), changing commodity market prices, principally for power and natural gas,
liquidity risk, counterparty credit risk and changes in interest rates. Because prices for power and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Significant volatility in both natural gas and power prices, as well as increased hedging and optimization activities, have had a significant impact on the presentation of our derivative assets and liabilities. Our derivative assets and liabilities have decreased to $2.3 billion and $(2.5) billion at September 30, 2009, compared to $4.1 billion and $(4.5) billion at December 31, 2008, respectively. As of September 30, 2009, the fair value of our level 3 derivative assets and liabilities represent only a small portion of our total assets and liabilities (less than 1%). There is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the three and nine months ended September 30, 2009, have reflected this as discussed below.
The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2009, through September 30, 2009, is summarized in the table below (in millions):
| | | Interest Rate | | Commodity | | | |
| | | Swaps | | Instruments | | Total | |
| Fair value of contracts outstanding at January 1, 2009 | | $ | (452 | ) | $ | 12 | | $ | (440 | ) |
| Losses recognized or otherwise settled during the period | | | 128 | (1) | | 198 | (2) | | 326 | |
| Fair value attributable to new contracts | | | (2 | ) | | (116 | ) | | (118 | ) |
| Changes in fair value attributable to price movements | | | (7 | ) | | 90 | | | 83 | |
| Changes in fair value attributable to nonperformance risk | | | (48 | ) | | (1 | ) | | (49 | ) |
Fair value of contracts outstanding at September 30, 2009(3) | | $ | (381 | ) | $ | 183 | | $ | (198 | ) |
__________
| (1) | Interest rate settlements consist of recognized losses from interest rate cash flow hedges of $(116) million and recognized losses from undesignated interest rate swaps of $(12) million (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations). |
| (2) | Settlement of commodity contracts not designated as hedging instruments of $(134) million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Condensed Statements of Operations) and $(64) million related to recognition of gains from cash flow hedges, previously reflected in OCI, offset by other changes in derivative assets and liabilities not reflected in OCI or net income. |
| (3) | Net commodity and interest rate derivative assets and liabilities reported in Notes 7 and 8 of the Notes to Consolidated Condensed Financial Statements. |
The change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in cash for option premiums paid or collected, in OCI, net of tax, for cash flow hedges, or on our Consolidated Condensed Statements of Operations as a component (gain or loss) in current earnings.
The components of our total mark-to-market gain (loss) from our commodity instruments and interest rate swaps for the three and nine months ended September 30, 2009 and 2008, are outlined below (in millions):
| | Three Months Ended September 30, | | Nine Months Ended September 30, | |
| | 2009 | | 2008 | | 2009 | | 2008 | |
Realized gain (loss)(1) | | $ | (2 | ) | | $ | (33 | ) | | $ | (27 | ) | | $ | (101 | ) |
| Unrealized gain (loss) | | | 44 | | | | 47 | | | | 67 | | | | (16 | ) |
| Total mark-to-market gain (loss) | | $ | 42 | | | $ | 14 | | | $ | 40 | | | $ | (117 | ) |
__________
| (1) | Balance includes a non-cash gain from amortization of prepaid power sales agreements of approximately $13 million and $33 million for the three and nine months ended September 30, 2008, respectively. |
Our change in AOCI from an accumulated loss of $(158) million at December 31, 2008, to an accumulated loss of $(250) million at September 30, 2009, was primarily driven by the effect of a decrease in power and natural gas prices, reclassification adjustment for cash flow hedges realized in net income, a decrease in interest rates and the effect of income taxes.
Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of power and natural gas. We manage the commodity price risk and the variability in future cash flows from forecasted sales of power and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative and non-derivative instruments.
The fair value of outstanding derivative commodity instruments at September 30, 2009, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):
| Fair Value Source | | 2009 | | | | 2010-2011 | | | | 2012-2013 | | | After 2013 | | | Total | |
| Prices actively quoted | | $ | 123 | | | $ | (223 | ) | | $ | — | | | $ | — | | | $ | (100 | ) |
| Prices provided by other external sources | | | 149 | | | | 121 | | | | 12 | | | | — | | | | 282 | |
| Prices based on models and other valuation methods | | | — | | | | — | | | | — | | | | 1 | | | | 1 | |
| Total fair value | | $ | 272 | | | $ | (102 | ) | | $ | 12 | | | $ | 1 | | | $ | 183 | |
We measure the commodity price risks in our portfolio on a daily basis using a VAR model to estimate the maximum potential one-day risk of loss resulting from market movements in comparison to internally established thresholds. Our VAR is calculated for our entire portfolio which is comprised of commodity derivatives, power plants, PPAs, and other physical and financial transactions. The portfolio VAR calculation incorporates positions for the remaining portion of the current calendar year plus the following two calendar years. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period, and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.
The table below presents the high, low and average of our daily VAR for the three and nine months ended September 30, 2009 and 2008, as well as our VAR at September 30, 2009 and 2008 (in millions):
| | | 2009 | | | 2008 | |
| Three months ended September 30: | | | | | | |
| High | | $ | 50 | | | $ | 66 | |
| Low | | $ | 36 | | | $ | 44 | |
| Average | | $ | 44 | | | $ | 57 | |
| Nine months ended September 30: | | | | | | | | |
| High | | $ | 59 | | | $ | 70 | |
| Low | | $ | 36 | | | $ | 39 | |
| Average | | $ | 49 | | | $ | 52 | |
| As of September 30 | | $ | 45 | | | $ | 47 | |
Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Increasing natural gas prices or Market Heat Rates can cause increased collateral requirements. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 9 of the Notes to Consolidated Condensed Financial Statements.
Credit Risk — Credit risk relates to the risk of loss resulting from non-performance or non-payment by our counterparties related to their contractual obligations with us. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We also have credit risk if counterparties are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:
| | • | Routine monitoring of counterparties’ credit limits and their overall credit ratings; |
| | • | Limiting our marketing, hedging and optimization activities with high risk counterparties; |
| | • | Margin, collateral, or prepayment arrangements; and |
| | • | Payment netting agreements, or master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. |
We believe that our credit policies adequately monitor and diversify our credit risk. We currently have no individual significant concentrations of credit risk to a single counterparty; however, a series of defaults or events of nonperformance by several of our individual counterparties could impact our liquidity and future results of operations. We monitor and manage our total comprehensive credit risk associated with all of our contracts and PPAs irrespective of whether they are accounted for as a normal purchase or normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Condensed Balance Sheets. Our counterparty credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and liabilities at September 30, 2009, and the period during which the instruments will mature are summarized in the table below (in millions):
| Credit Quality | | | | | | | | | | | | | | | |
| (Based on Standard & Poor’s Ratings as of September 30, 2009) | | 2009 | | | | 2010-2011 | | | | 2012-2013 | | | After 2013 | | | Total | |
| Investment grade | | $ | 272 | | | $ | (100 | ) | | $ | 14 | | | $ | — | | | $ | 186 | |
| Non-investment grade | | | — | | | | (2 | ) | | | (2 | ) | | | — | | | | (4 | ) |
| No external ratings | | | — | | | | — | | | | — | | | | 1 | | | | 1 | |
| Total fair value | | $ | 272 | | | $ | (102 | ) | | $ | 12 | | | $ | 1 | | | $ | 183 | |
Interest Rate Risk — We are exposed to interest rate risk related to our variable rate debt. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. Our variable rate financings are indexed to base rates, generally LIBOR. Significant LIBOR increases could have an adverse impact on our future interest expense.
Our fixed-rate debt instruments do not expose us to the risk of loss in earnings due to changes in market interest rates. In general, such a change in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of the fixed rate debt in the open market prior to their maturity.
Currently, we use interest rate swaps to adjust the mix between fixed and floating rate debt as a hedge of our interest rate risk. We do not use interest rate derivative instruments for trading purposes. In order to manage our risk to significant increases in LIBOR, we have effectively hedged $7.1 billion of our variable rate debt through September 30, 2010, through the use of variable to fixed interest rate swaps, the majority of which mature in years 2009 through 2012. To the extent eligible, our interest rate swaps have been designed as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective. As of September 30, 2009, approximately $11 million was recorded in AOCI for interest rate swaps that were hedging the variable interest rates on the retired First Lien Credit Facility term loans, which were exchanged for First Lien Notes on October 21, 2009. We expect that these interest rate swaps will no longer qualify as cash flow hedges.
The issuance of our First Lien Notes and our CCFC Refinancing have reduced our exposure to fluctuating interest rates by refinancing approximately $2.3 billion in variable interest rate debt (including our CCFCP Preferred Shares) with $2.2 billion of fixed interest rate debt. The following table summarizes the contract terms as well as the fair values of our significant financial instruments exposed to interest rate risk as of September 30, 2009. All outstanding balances and fair market values are shown gross of applicable premium or discount, if any (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | Fair Value | |
| | | | | | | | | | | | | | | | | | | | | | | | September 30, | |
| | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | Thereafter | | | Total | | | 2009 | |
| Debt by Maturity Date: | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Rate | | $ | 4 | | | $ | 217 | | | $ | 71 | | | $ | 21 | | | $ | 24 | | | $ | 1,132 | | | $ | 1,469 | | | $ | 1,453 | |
| Average Interest Rate | | | 9.5 | % | | | 6.5 | % | | | 6.9 | % | | | 9.6 | % | | | 9.6 | % | | | 7.9 | % | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Variable Rate | | $ | 19 | | | $ | 184 | | | $ | 960 | | | $ | 207 | | | $ | 77 | | | $ | 5,910 | | | $ | 7,357 | | | $ | 6,757 | |
Average Interest Rate(1) | | | 2.9 | % | | | 3.6 | % | | | 3.7 | % | | | 4.5 | % | | | 4.6 | % | | | 6.5 | % | | | | | | | | |
| (1) | Projection based upon anticipated LIBOR rates. |
See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting requirements and disclosures.
See “Risk Management and Commodity Accounting” in Item 2.
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief
Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon, and as of the date of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
During the third quarter of 2009, there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II — OTHER INFORMATION
See Note 14 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.
Various risk factors could have a negative effect on our business, financial position, cash flows and results of operations. These include the following risk factors, in addition to the risk factors set forth in “Item 1A. Risk Factors” in our 2008 Form 10-K:
Existing and future anticipated GHG/Carbon legislation could adversely affect our operations.
Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. In particular, there is growing likelihood that carbon tax or limits on carbon, CO2 and other GHG emissions will be implemented at the federal or expanded at the state or regional levels.
In 2009, ten states in the northeast began the compliance period of a cap-and-trade program, RGGI, to regulate CO2 emissions from power plants. California is in the process of creating implementation plans for Assembly Bill 32 which places a statewide cap on GHG emissions and requires the state to return to 1990 emission levels by 2020.
In 2008, there were several bills introduced in the U.S. Congress concerning climate change. On June 26, 2009, the House of Representatives passed The American Clean Energy and Security Act of 2009, a climate change and clean energy bill, which, among other provisions, would establish an economy-wide carbon cap-and-trade program and set carbon emission reduction targets in several sectors of the economy, including the power sector. For the power sector, 2012 is set as the initial year for compliance. On October 23, 2009, draft climate change legislation entitled the Clean Energy Jobs and American Power Act, was released in the Senate. The legislation is similar to The American Clean Energy and Security Act of 2009 in that it also includes, among other provisions, an economy-wide carbon cap-and-trade program.
If either bill were to become law, we would have the obligation to obtain emissions allowances for the operation of our fossil-fuel power plants. While we expect the costs to acquire allowances to be a factor that will impact market price, there can be no assurance that market price will fully reflect these costs which could adversely affect our Commodity Margin. With respect to our existing long-term steam and power contracts under which we would not be able to recover costs to acquire allowances from our customers, the bill allocates a pool of free allowances to generators with qualifying contracts to mitigate such costs. However, there can be no assurance there will be a sufficient number of free allowances in the pool to fully cover emissions related to generation under such contracts which could adversely impact our Commodity Margin.
Although we cannot predict the effect and ultimate content of final climate change legislation and regulations, if any, on our business, we continue to expect climate change legislation efforts to proceed at the federal level, and that proposed legislation will take the form of a cap-and-trade program, although it is possible that legislation may take other forms, such as a carbon tax on each unit of CO2 or GHG emitted in excess of mandated limits. As a result of requirements for GHG emissions reduction, we could be required under any climate change legislation or related regulations ultimately enacted to purchase allowances or offsets to emit GHGs or other regulated pollutants or to pay taxes on such emissions. These requirements, as well as the possibility that market or contract prices will not fully reflect costs of compliance, or that we may not be able to obtain free allowances or recoup our costs to obtain allowances or to reduce emissions, could have a material impact on our business or results of operations.
Claims that some geothermal plants cause increased risk of seismic activity could delay or increase the cost of further development at The Geysers.
In 2009, as part of a joint private and federally-funded geothermal technology research project, a company unrelated to us commenced deepening an existing geothermal well on a property neighboring our Geysers Assets in northern California, and reportedly was attempting to drill into the hot, low or non-permeable base rock that underlies the existing geothermal steam reservoir at The Geysers to engineer or create a “multilayered heat extraction system” below the reservoir by injecting water under very high pressure, fracturing the rock. While there is general agreement that the operation of certain geothermal plants may cause low level seismic activity, the fracturing of deep bedrock caused by the multilayered heat extraction system is believed to create a greater risk of more serious seismic activity and has spawned public and political concern due to this risk. As a consequence, in June 2009, the Department of Energy began requiring all geothermal research grant applicants to comply with a published seismic mitigation protocol, and, in July 2009, the Department of Energy temporarily halted funding of its portion of that research project pending further seismicity studies. Although our geothermal operations do not include attempts to engineer or create new reservoirs from hot, low or non-permeable rock, the concerns regarding induced seismicity from geothermal operations could delay or otherwise adversely impact our Department of Energy grant applications. In addition, it is possible that government entities or agencies will seek to more stringently regulate the exploration, development and operation of geothermal facilities, including operations of our Geysers Assets, in order to mitigate induced seismicity resulting from geothermal operations, or that operators of geothermal power plants could be subject to property damage claims resulting from increased seismic activity. Any of these events could increase the cost of operating the existing Geysers Assets and may delay or increase further exploration and any further development of our Geysers Assets.
Repurchase of Equity Securities. Upon vesting of restricted stock awarded by us to employees, we withhold shares to cover employees’ tax withholding obligations, other than for employees who have chosen to make tax withholding payments in cash. As set forth in the table below, during the third quarter of 2009, we withheld a total of 27,642 shares in the indicated months. These were the only repurchases of equity securities made by us during this period. We do not have a stock repurchase program.
| | | | | | | (c) | | (d) | |
| | | | | | | Total Number of | | Maximum Number | |
| | | | | | | Shares Purchased | | of Shares That May | |
| | | (a) | | (b) | | as Part of | | Yet Be Purchased | |
| | | Total Number of | | Average Price | | Publicly Announced | | Under the | |
| Period | | Shares Purchased | | Paid Per Share | | Plans or Programs | | Plans or Programs | |
| July | | — | | $ | — | | — | | n/a | |
| August | | 27,642 | | $ | 13.00 | | — | | n/a | |
| September | | — | | $ | — | | — | | n/a | |
| Total | | 27,642 | | $ | 13.00 | | — | | n/a | |
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
| Exhibit | | |
| Number | | Description |
| | | |
| 1.1 | | Underwriting Agreement, dated September 22, 2009, among Calpine Corporation, the selling stockholder named therein and Morgan Stanley & Co. Incorporated, the underwriter named therein (incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K/A filed with the SEC on September 23, 2009). |
| | | |
| 3.1 | | Amended and Restated Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed with the SEC on February 1, 2008). |
| | | |
| 3.2 | | Amended and Restated Bylaws of the Company (as amended through May 7, 2009) (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, filed with the SEC on July 31, 2009). |
| | | |
| 4.1 | | Indenture, dated October 21, 2009, between Calpine Corporation and Wilmington Trust Company, as trustee, including form of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on October 26, 2009). |
| | | |
| 10.1 | | Credit Agreement, dated as of January 31, 2008, among Calpine Corporation, as borrower, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding, Inc., as co-documentation agents and as co-syndication agents, General Electric Capital Corporation, as sub-agent for the revolving lenders, Goldman Sachs Credit Partners L.P., as administrative agent and as collateral agent and each of the financial institutions from time to time party thereto (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the SEC on February 1, 2008). |
| | | |
| 10.2 | | First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, certain of Calpine Corporation’s subsidiaries as guarantors, the financial institutions party thereto as lenders and Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent. (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on August 26, 2009). |
| | | |
| 31.1 | | Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes Oxley Act of 2002.* |
| | | |
| 31.2 | | Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* |
| | | |
| 32.1 | | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* |
__________
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
CALPINE CORPORATION
| | | By: | /s/ ZAMIR RAUF | |
| | | | Zamir Rauf | |
| | | | Executive Vice President and | |
| | | | Chief Financial Officer | |
| | | | | |
| | Date: October 29, 2009 | | | |
| | | By: | /s/ JIM D. DEIDIKER | |
| | | | Jim D. Deidiker | |
| | | | Senior Vice President and | |
| | | | Chief Accounting Officer | |
| | | | | |
| | Date: October 29, 2009 | | | |
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX
| Exhibit | | |
| Number | | Description |
| | | |
| 1.1 | | Underwriting Agreement, dated September 22, 2009, among Calpine Corporation, the selling stockholder named therein and Morgan Stanley & Co. Incorporated, the underwriter named therein (incorporated by reference to Exhibit 1.1 to our Current Report on Form 8-K/A filed with the SEC on September 23, 2009). |
| | | |
| 3.1 | | Amended and Restated Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed with the SEC on February 1, 2008). |
| | | |
| 3.2 | | Amended and Restated Bylaws of the Company (as amended through May 7, 2009) (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, filed with the SEC on July 31, 2009). |
| | | |
| 4.1 | | Indenture, dated October 21, 2009, between Calpine Corporation and Wilmington Trust Company, as trustee, including form of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on October 26, 2009). |
| | | |
| 10.1 | | Credit Agreement, dated as of January 31, 2008, among Calpine Corporation, as borrower, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding, Inc., as co-documentation agents and as co-syndication agents, General Electric Capital Corporation, as sub-agent for the revolving lenders, Goldman Sachs Credit Partners L.P., as administrative agent and as collateral agent and each of the financial institutions from time to time party thereto (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the SEC on February 1, 2008). |
| | | |
| 10.2 | | First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, certain of Calpine Corporation’s subsidiaries as guarantors, the financial institutions party thereto as lenders and Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent. (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on August 26, 2009). |
| | | |
| 31.1 | | Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes Oxley Act of 2002.* |
| | | |
| 31.2 | | Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.* |
| | | |
| 32.1 | | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* |
__________
