-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, UZ3LxrR0ri18Xo6zIG00btl4gqShatcoYOFaW+XeUURTs5X9PTJatxV6jBR5sA9N 3X+fBE4ounvy9vUTYNM1tA== 0000916457-03-000041.txt : 20030723 0000916457-03-000041.hdr.sgml : 20030723 20030723171724 ACCESSION NUMBER: 0000916457-03-000041 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010930 ITEM INFORMATION: Other events FILED AS OF DATE: 20030723 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALPINE CORP CENTRAL INDEX KEY: 0000916457 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 770212977 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-12079 FILM NUMBER: 03798935 BUSINESS ADDRESS: STREET 1: 50 WEST SAN FERNANDO ST CITY: SAN JOSE STATE: CA ZIP: 95113 BUSINESS PHONE: 4089955115 MAIL ADDRESS: STREET 1: 50 W SAN FERNANDO STREET 2: SUITE 500 CITY: SAN JOSE STATE: CA ZIP: 95113 8-K 1 o72303.txt ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ----------------------------- FORM 8-K ----------------------------- CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of report (Date of earliest event reported): July 16, 2003 CALPINE CORPORATION (A Delaware Corporation) 001-12079 77-0212977 (Commission File Number) (I.R.S. Employer Identification No) 50 West San Fernando Street San Jose, California 95113 Telephone: (408) 995-95115 ================================================================================ Item 5. Other Events On July 16, 2003, Calpine Corporation (the "Company") completed its offering of $2.55 billion of second-priority senior secured notes in a private placement transacted pursuant to Rule 144A of the Securities Act of 1933. Concurrently, Calpine also closed on a $750 million Senior Secured Term Loan Credit Agreement with Goldman Sachs Credit Partners L.P. and the other lending institutions party thereto and on a $500 million amendment and restatement to its existing senior secured credit facilities. In connection with the offering and prior to the issuance of the notes, the Company delivered a confidential offering circular dated July 10, 2003 (the "Confidential Offering Circular") to certain institutional investors. In addition to describing the terms of the offering, the Confidential Offering Circular included information that is not included in the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 or in its Annual Report on Form 10-K for the year ended December 31, 2002 that may be of interest to investors. Set forth below are excerpts of the following three portions of the Confidential Offering Circular: Pending Transactions - This section provides additional details regarding pending financing transactions. Risk Factors - This section reflects updates and modifications to the risk factors contained in our Annual Report on Form 10-K for the year ended December 31, 2002. Use of Proceeds - This section updates prior disclosures regarding sources and uses of capital after giving effect to the transactions described in the Confidential Offering Circular. This Current Report on Form 8-K is filed solely to make available to our investors the information referred to above that was provided to institutional investors in the Confidential Offering Circular. In providing this information, we undertake no duty to update this or any other information except as otherwise required by relevant law. We also direct readers to our annual, quarterly and other reports that have been filed with or furnished to the SEC subsequent to the date of the Confidential Offering Circular, or that may be filed with or furnished to the SEC after the date of this Current Report on Form 8-K, which may contain information that updates or otherwise modifies the information contained herein. The terms "Calpine", the "company", "we", "our" and "us" in this Report on Form 8-K refer to Calpine Corporation and its subsidiaries. References to "new term loans" or to our "new senior secured credit facility" refer to the $750 million Senior Secured Term Loan Credit Agreement and the $500 million Amended and Restated Senior Secured Credit Facility, respectively, referred to above. PENDING TRANSACTIONS - -------------------- Calpine has announced that it intends to proceed with the implementation of a liquidity strategy of monetizing power contracts, selling certain power generating assets and engaging in project financing transactions. These transactions include a secured financing of certain of Calpine's subsidiaries' California peaking facilities, a refinancing by CCFC I of its approximately $970.1 million revolving credit facility and a monetization of certain Canadian power plant assets through the Canadian Power Income Fund subsidiary. In addition, the Company continues to evaluate and pursue other transactions relating to power contract monetizations, assets sales and other financings of project facilities, which may include debt financings or the issuance of preferred equity interests by our subsidiaries. RISKS FACTORS - ------------- WE MUST REFINANCE OUR DEBT MATURING IN 2003 AND 2004. In May 2003, our existing $950 million revolving credit facility under our senior secured credit facilities expired and we reached agreement with certain members of the current bank group on a term sheet for a new, two-year senior secured credit facility. We have an extension of the maturity date for our existing $950 million term loan to July 16, 2003. We intend to amend and restate our existing senior secured credit facilities to provide for a new $500 million senior secured facility, which has a revolving credit facility and a term loan portion. We will repay outstanding indebtedness on our existing senior secured facilities using the proceeds of this offering. We previously extended the termination date of our letters of credit outstanding under our existing senior secured credit facilities from May 2003 through dates up to May 2004. In November 2003 and 2004, respectively, our $1.0 billion CCFC I and $2.5 billion CCFC II secured revolving construction financing facilities will mature, requiring us to refinance this indebtedness. At March 31, 2003, we had $949.6 million in funded borrowings outstanding under the existing term loan facility, and $340.0 million in funded borrowings and $519.5 million in letters of credit outstanding under the existing senior secured credit facilities. Under our CCFC I and CCFC II secured revolving construction financing facilities, we had $970.1 million and $2,468.8 million outstanding, respectively. In addition to the debt discussed above, $350.5 million and $30.2 million of miscellaneous debt and capital lease obligations are maturing in 2003 and 2004, respectively. Our intent is to refinance all or a portion of such indebtedness, extend the maturity of the financing or obtain additional financing. Our ability to refinance this indebtedness will depend, in part, on events beyond our control, including the significant contraction in the availability of capital for participants in the energy sector, and actions taken by rating agencies. If we are unable to refinance this indebtedness, we may be required to further delay our construction program, sell assets or obtain additional financing. We may not be able to complete any such refinancing or asset sale, or obtain additional financing, on terms acceptable to us, or at the time needed or in the amounts required. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" in our Annual Report on Form 10-K for the year ended December 31, 2002. We have $3.4 billion of debt due in 2004 and are subject to a holders' put on December 26, 2004 requiring us to repurchase all or a portion of our $1.2 billion in aggregate principal amount of 4% Convertible Senior Notes Due 2006 then outstanding through cash, stock or a combination thereof. In addition, $268.7 million of our outstanding Remarketable Term Income Deferrable Equity Securities ("HIGH TIDES") are scheduled to be remarketed no later than November 1, 2004, $351.6 million of our HIGH TIDES are scheduled to be remarketed no later than February 1, 2005 and $504.0 million of our HIGH TIDES are scheduled to be remarketed no later than August 1, 2005. In the event of a failed remarketing, the relevant HIGH TIDES will remain outstanding as convertible securities at a term rate equal to the treasury rate plus 6% per annum and with a term conversion price equal to 105% of the average closing price of our common stock for the five consecutive trading days after the applicable final failed remarketing termination date. In addition, we have approximately $277 million of debt due in 2005. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness when due, including these notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including these notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our new senior secured credit facility, the new term loans and these notes, on commercially reasonable terms or at all. -2- WE MAY BE UNABLE TO SECURE ADDITIONAL FINANCING IN THE FUTURE. Each power generation facility that we acquire or develop will require substantial capital investment. Our ability to arrange financing (including any extension or refinancing) and the cost of the financing are dependent upon numerous factors. Access to capital (including any extension or refinancing) for participants in the energy sector, including for us, has been significantly restricted since late 2001. Other factors include: o general economic and capital market conditions; o conditions in energy markets; o regulatory developments; o credit availability from banks or other lenders for us and our industry peers, as well as the economy in general; o investor confidence in the industry and in us; o the continued success of our current power generation facilities; and o provisions of tax and securities laws that are conducive to raising capital. We have financed our existing power generation facilities using a variety of leveraged financing structures, consisting of senior secured and unsecured indebtedness, construction financing, project financing, revolving credit facilities, term loans and lease obligations. Most of our construction costs during 2002 were financed through one of our two Calpine Construction Finance Company ("CCFC") debt facilities. As of March 31, 2003, we had approximately $14.1 billion of total consolidated funded debt, consisting of $0.9 billion of secured term debt, $4.5 billion of secured construction/project financing, $0.2 billion of capital lease obligations, $6.9 billion in senior notes, $1.2 billion in convertible senior notes, and $0.4 billion of secured and unsecured notes payable and borrowings under lines of credit. Each project financing and lease obligation is structured to be fully paid out of cash flow provided by the facility or facilities financed or leased. In the event of a default under a financing agreement which we do not cure, the lenders or lessors would generally have rights to the facility and any related assets. In the event of foreclosure after a default, we might not retain any interest in the facility. While we intend to utilize non-recourse or lease financing when appropriate, market conditions and other factors may prevent similar financing for future facilities. We do not believe the lack of availability of non-recourse or lease financing will significantly affect our ability to continue to borrow funds in the future in order to finance new facilities. However, it is possible that we may be unable to obtain the financing required to develop our power generation facilities on terms satisfactory to us. We have from time to time guaranteed certain obligations of our subsidiaries and other affiliates. Our lenders or lessors may also seek to have us guarantee the indebtedness for future facilities. Guarantees render our general corporate funds vulnerable in the event of a default by the facility or related subsidiary. Additionally, certain of our indentures may restrict our ability to guarantee future debt, which could adversely affect our ability to fund new facilities. Our indentures, including the indentures for the notes offered by this offering circular, do not limit the ability of our subsidiaries to incur non-recourse or lease financing for investment in new facilities. OUR CREDIT RATINGS HAVE BEEN DOWNGRADED AND COULD BE DOWNGRADED FURTHER. On June 20, 2003, Moody's placed the rating of our long-term senior unsecured debt (currently rated at B1) under review for possible downgrade. We remain on credit watch with negative implications at Moody's. On June 2, 2003, Standard & Poor's downgraded our corporate credit rating from BB to B. We remain on credit watch with negative implications at Standard and Poor's. On December 9, 2002, Fitch, Inc. downgraded our long-term senior unsecured debt from BB to B+. Many other issuers in the power generation sector have also been downgraded by one or more of the ratings agencies during this period. Such downgrades can have a negative impact on our liquidity by reducing attractive financing opportunities and increasing the amount of collateral required by trading counterparties. We cannot assure you that Moody's, Fitch and Standard & Poor's will not further downgrade our credit ratings in the future. If any credit rating is downgraded, we could be required to, among other things, pay additional interest under our credit agreements, or provide additional guarantees, collateral, letters of credit or cash for credit support obligations, and it could increase our cost of capital, make our efforts to raise capital more difficult and have an adverse impact on our and our -3- subsidiaries' business, financial condition and results of operations. Although we are not seeking a rating for these notes, the rating agencies could choose to rate our notes in a manner that could reduce the trading value of our notes. Additionally, the completion of this offering could have a negative impact on the rating of the Company or its debt. REVENUE MAY BE REDUCED SIGNIFICANTLY UPON EXPIRATION OR TERMINATION OF OUR POWER SALES AGREEMENTS. Some of the electricity we generate from our existing portfolio is sold under long-term power sales agreements that expire at various times. We also sell power under short to intermediate (one to five year) contracts. When the terms of each of these various power sales agreements expire, it is possible that the price paid to us for the generation of electricity under subsequent arrangements may be reduced significantly. USE OF DERIVATIVES CAN CREATE VOLATILITY IN EARNINGS AND MAY REQUIRE SIGNIFICANT CASH COLLATERAL. During 2002, we recognized $26.1 million in mark-to-market gains on electric power and natural gas derivatives. Please see Item 7 -- "Management's Discussion and Analysis of Financial Condition and Results of Operation -- Impact of Recent Accounting Pronouncements" included in our Annual Report on Form 10-K for a detailed discussion of the accounting requirements relating to electric power and natural gas derivatives under SFAS No. 133, EITF 02-3 and related provisions of U.S. generally accepted accounting principles. In addition, GAAP treatment of derivatives in general, and particularly in our industry, continue to evolve. We may enter into other transactions in future periods that require us to mark various derivatives to market through earnings. The nature of the transactions that we enter into in addition to volatility of natural gas and electric power prices will determine the volatility of earnings that we may experience related to these transactions. As a result, in part, of the fallout from Enron's declaration of bankruptcy on December 2, 2001, companies using derivatives have become more sensitive to the inherent risks of such transactions. Consequently, companies, including us, are requiring cash collateral for certain derivative transactions in excess of what was previously required. As of March 31, 2003, we had $26.2 million in margin deposits with counterparties, net of deposits posted by counterparties with us, and had procured $74.6 million of letters of credit to support CES risk management activities, compared to $25.2 million and $106.1 million, respectively, at December 31, 2002. Movements in commodity prices as well as a reduction in our derivative activities during this period have reduced our need to post collateral in connection with these transactions. Future cash collateral requirements may increase based on the extent of our involvement in derivative activities and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market. WE MAY BE UNABLE TO OBTAIN AN ADEQUATE SUPPLY OF NATURAL GAS IN THE FUTURE. To date, our fuel acquisition strategy has included various combinations of our own gas reserves, gas prepayment contracts, short-, medium- and long-term supply contracts and gas hedging transactions. In our gas supply arrangements, we attempt to match the fuel cost with the fuel component included in the facility's power sales agreements in order to minimize a project's exposure to fuel price risk. In addition, the focus of CES is to manage the "spark spread" for our portfolio of generating plants -- the spread between the cost of fuel and electricity revenues -- and we actively enter into hedging transactions to lock in gas costs and spark spreads. We believe that there will be adequate supplies of natural gas available at reasonable prices for each of our facilities when current gas supplies agreements expire. However, gas supplies may not be available for the full term of the facilities' power sales agreements, and gas prices may increase significantly. Additionally, our credit ratings may inhibit our ability to procure gas supplies from third parties. If gas is not available, or if gas prices increase above the level that can be recovered in electricity prices, there could be a negative impact on our results of operations or financial condition. OUR POWER PROJECT DEVELOPMENT AND ACQUISITION ACTIVITIES MAY NOT BE SUCCESSFUL. The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, we must generally obtain: o necessary power generation equipment; o governmental permits and approvals; o fuel supply and transportation agreements; o sufficient equity capital and debt financing; o electrical transmission agreements; -4- o water supply and wastewater discharge agreements; and o site agreements and construction contracts. We may be unsuccessful in accomplishing any of these matters or in doing so on a timely basis. In addition, project development is subject to various environmental, engineering and construction risks relating to cost overruns, delays and performance. Although we may attempt to minimize the financial risks in the development of a project by securing a favorable power sales agreement, obtaining all required governmental permits and approvals, and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. If we are unable to complete the development of a facility, we might not be able to recover our investment in the project. The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We cannot assure you that we will be successful in the development of power generation facilities in the future. In particular, we cannot assure you that we will be able to successfully complete construction of the facilities that are included in the collateral, nor can we assure you that these facilities will be profitable or have value equal to the investment in them even if they do achieve commercial operation. WE HAVE GROWN SUBSTANTIALLY IN RECENT YEARS AS A RESULT OF ACQUISITIONS OF INTERESTS IN POWER GENERATION FACILITIES AND STEAM FIELDS. The integration and consolidation of our acquisitions with our existing business requires substantial management, financial and other resources and, ultimately, our acquisitions may not be successfully integrated. In addition, as we transition from a development company to an operating company, we are not likely to continue to grow at historical rates due to acquisition activities in the near future. Although the domestic power industry is continuing to undergo consolidation and may offer acquisition opportunities at favorable prices, we believe that we are likely to confront significant competition for those opportunities and, due to the constriction in the availability of capital resources for acquisitions and other expansion, to the extent that any opportunities are identified, we may be unable to effect any acquisitions. As discussed in "Item 7. -- Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K, we have substantially curtailed our development efforts in response to our reduced liquidity. Conversely, to the extent we seek to divest assets, we may not be able to do so at attractive prices. OUR PROJECTS UNDER CONSTRUCTION MAY NOT COMMENCE OPERATION AS SCHEDULED. The commencement of operation of a newly constructed power generation facility involves many risks, including: o start-up problems; o the breakdown or failure of equipment or processes; and o performance below expected levels of output or efficiency. New plants have no operating history and may employ recently developed and technologically complex equipment. Insurance (including a layer of insurance provided by a captive insurance subsidiary) is maintained to protect against certain risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover lost revenues or increased expenses. As a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation, unless cured, could result in losing our interest in a power generation facility. In certain situations, power sales agreements entered into with a utility early in the development phase of a project may enable the utility to terminate the agreement, or to retain security posted as liquidated damages, if a project fails to achieve commercial operation or certain operating levels by specified dates or fails to make specified payments. In the event a termination right is exercised, the default provisions in a financing agreement may be triggered (rendering such debt immediately due and payable). As a result, the project may be rendered insolvent and we may lose our interest in the project. In recent years we have relied less and less on traditional project financing, so the risk of a financing agreement default linked to a default under a power sales agreement comes into play infrequently. -5- OUR POWER GENERATION FACILITIES MAY NOT OPERATE AS PLANNED. Upon completion of our projects currently under construction, we will operate 97 of the 100 power plants in which we will have an interest. The continued operation of power generation facilities, including, upon completion of construction, the facilities owned directly by Calpine and included in the collateral, involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes, and performance below expected levels of output or efficiency. Although from time to time our power generation facilities have experienced equipment breakdowns or failures, these breakdowns or failures have not had a significant effect on the operation of the facilities or on our results of operations. For calendar year 2002, our gas-fired and geothermal power generation facilities operated at an average availability of approximately 92% and 97%, respectively. Although our facilities contain various redundancies and back-up mechanisms, a breakdown or failure may prevent the affected facility from performing under applicable power sales agreements. In addition, although insurance is maintained to protect against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. For example, we have recently experienced performance issues with a new line of turbines, which has resulted in operational delays. As a result, we could be unable to service principal and interest payments under our financing obligations which could result in losing our interest in the power generation facility. WE CANNOT ASSURE THAT OUR ESTIMATES OF OIL AND GAS RESERVES ARE ACCURATE. Estimates of proved oil and gas reserves and the future net cash flows attributable to those reserves are prepared by independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and cash flows attributable to such reserves, including factors beyond our control and that of our engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and gas prices and expenditures for future development and exploration activities, and of engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions based upon production history, development and exploration activities and prices of oil and gas. Actual future production, revenue, taxes, development expenditures, operating expenses, underlying information, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and underlying information set forth herein. In addition, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. OUR GEOTHERMAL ENERGY RESERVES MAY BE INADEQUATE FOR OUR OPERATIONS. The development and operation of geothermal energy resources are subject to substantial risks and uncertainties similar to those experienced in the development of oil and gas resources. The successful exploitation of a geothermal energy resource ultimately depends upon: o the heat content of the extractable fluids; o the geology of the reservoir; o the total amount of recoverable reserves; o operating expenses relating to the extraction of fluids; o price levels relating to the extraction of fluids or power generated; and o capital expenditure requirements relating primarily to the drilling of new wells. In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the electrical power capacity desired. An incorrect estimate by us or an unexpected decline in productivity could, if material, adversely affect our financial condition or results of operations. Geothermal reservoirs are highly complex. As a result, there exist numerous uncertainties in determining the extent of the reservoirs and the quantity and productivity of the steam reserves. Reservoir engineering is an inexact process of estimating underground accumulations of steam or fluids that cannot be measured in any precise way, and depends significantly on the quantity and accuracy of available data. As a result, the estimates of other reservoir specialists may differ materially from ours. Estimates of reserves are generally revised over time on the basis of the results of drilling, testing and -6- production that occur after the original estimate was prepared. We cannot assure that we will be able to successfully manage the development and operation of our geothermal reservoirs or that we will accurately estimate the quantity or productivity of our steam reserves. THE ULTIMATE OUTCOME OF THE LEGAL PROCEEDINGS RELATING TO OUR ACTIVITIES CANNOT BE PREDICTED. ANY ADVERSE DETERMINATION COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Calpine is party to various litigation matters arising out of the normal course of business, the more significant of which are summarized in Item 3. Legal Proceedings in of our Annual Report on Form 10-K for the year ended December 31, 2002. These matters include securities class action lawsuits, such as Hawaii Structural Ironworkers Pension Fund v. Calpine et al, which relates to our April 2002 equity offering and also named Goldman, Sachs & Co. and the other named underwriters of that offering as defendants. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome in each case presently be reasonably estimated. The liability Calpine may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently reserved with respect to such matters and, as a result, these matters may potentially be material to Calpine's financial condition and results of operations. WE DEPEND ON OUR ELECTRICITY AND THERMAL ENERGY CUSTOMERS. Our systems of power generation facilities rely on one or more power sales agreements with one or more utilities or other customers for a substantial portion of our revenue. In addition, sales of electricity to one customer during 2002, the California Department of Water Resources ("DWR"), comprised approximately 10% of our total revenue that year. The loss of significant power sales agreements with DWR or an adverse change in DWR's ability to pay for power delivered under our contracts could have a negative effect on our results of operations. In addition, any material failure by any customer to fulfill its obligations under a power sales agreement could have a negative effect on the cash flow available to us and on our results of operations. COMPETITION COULD ADVERSELY AFFECT OUR PERFORMANCE. The power generation industry is characterized by intense competition, and we encounter competition from utilities, industrial companies and other independent power producers. In recent years, there has been increasing competition in an effort to obtain power sales agreements, and this competition has contributed to a reduction in electricity prices in certain markets. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. In California, the California Public Utilities Commission ("CPUC") issued decisions that provide for direct access for all customers as of April 1, 1998; however, the CPUC suspended direct access in California effective September 20, 2001 due to the recent problems that arose in California's newly-deregulated markets. As a result, uncertainty exists as to the future course for direct access in California in the aftermath of the energy crisis in that state. In Texas, legislation phases-in a deregulated power market, which commenced on January 1, 2001. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the supply of electricity in the future will increase this pressure. OUR INTERNATIONAL INVESTMENTS MAY FACE UNCERTAINTIES. We have investments in oil and natural gas resources and power projects in Canada in development and in operation, and an investment in a power generation facility in the U.K. that is in operation, and we may pursue additional international investments in the future subject to the limitations on our expansion plans due to current capital market constraints. International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the countries in which we invest. Risks specifically related to investments in non-United States projects may include: o fluctuations in currency valuation; o currency inconvertibility; o expropriation and confiscatory taxation; o increased regulation; and o approval requirements and governmental policies limiting returns to foreign investors. -7- THE UNRESOLVED ISSUES ARISING FROM THE CALIFORNIA POWER MARKET, WHERE 42 OF OUR 100 POWER PLANTS ARE LOCATED, COULD ADVERSELY AFFECT OUR PERFORMANCE. The volatility in the California power market from mid-2000 through mid-2001 has produced significant unanticipated results. CALIFORNIA LONG-TERM SUPPLY CONTRACTS. In 2001, California adopted legislation permitting it to issue long-term revenue bonds to fund wholesale purchases of power by the California Department of Water Resources ("DWR"). The bonds will be repaid with the proceeds of payments by retail power customers over time. CES and DWR entered into four long-term supply contracts during 2001. In early 2002, the California Public Utilities Commission ("CPUC") and the California Electricity Oversight Board ("EOB") filed complaints under the Federal Power Act ("FPA"), Section 206, with the FERC alleging that the prices and terms of the long-term contracts with DWR were unjust and unreasonable and contrary to the public interest (the "206 Complaint"). The contracts entered into by CES and DWR were subject to the 206 Complaint. On April 22, 2002, we announced that we had renegotiated CES' long-term power contracts with DWR and settled the 206 Complaint. The Office of the Governor, the CPUC, the EOB and the Attorney General for the State of California all endorsed the renegotiated contracts and dropped all pending claims against Calpine and its affiliates, including any efforts by the CPUC and the EOB to seek refunds from Calpine and its affiliates through the FERC California Refund Proceedings. In connection with the renegotiation, we agreed to pay $6 million over three years to the State Attorney General to resolve any possible claims. Despite our settlement with DWR, we cannot predict whether third parties may make claims relating to the contracts. CALIFORNIA ELECTRIC POWER FUND. In November 2002, DWR completed the issuance of $11.3 billion aggregate principal amount in revenue bonds. Part of the proceeds from this bond issuance was used to fund the Electric Power Fund (the "Fund"), which will be used to meet DWR's payment obligations under its long-term energy contracts. Revenue requirements for the repayment of the bonds will be determined at least annually and submitted to the CPUC. Under the terms of a Rate Agreement between the DWR and the CPUC, the CPUC is required to set rates for the customers of the State's investor-owned utilities ("IOUs"), such that the Fund will always have monies to retire the bonds when due. DWR is shifting certain power procurement responsibilities to the IOUs, other than those procurement obligations already committed under the terms of its long-term contracts, such as the four long-term contracts with CES discussed above. Ultimately, the financial responsibility for the long-term contracts may be transferred to the IOUs such as, P G and E; however, this will not occur until a number of issues are addressed, including IOU creditworthiness. Nevertheless, in the event that the DWR contracts were transferred or assigned to, or if we entered into a replacement power sales agreement with, another party, we could look for payment only to that third party, and not to DWR or the Fund. We would be an unsecured creditor of that third party. CALIFORNIA REFUND PROCEEDING. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric Company and under Section 206 of the Federal Power Act alleging, among other things, that the markets operated by the CAISO and the CalPX were dysfunctional. In addition to commencing an inquiry regarding the market structure, FERC established a refund effective period of October 2, 2000, to June 19, 2001, for sales made into those markets. On December 12, 2002, the Presiding Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability ("December 12 Certification") making an initial determination of refund liability. On March 26, 2003, FERC also issued an order adopting many of such Judge's findings set forth in the December 12 Certification (the "March 26 Order"). In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the refund period, FERC ordered that the basis for calculating a party's potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the refund proceeding. We believe, based on the available information, that any refund liability that may be attributable to us will increase modestly, from approximately $6.2 million to approximately $8.4 million, after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to Calpine. We have fully reserved the amount of refund liability that by our analysis would potentially be owed under the refund calculation clarification in the March 26 order. The final determination of the refund liability is subject to further Commission proceedings to ascertain the allocation of payment obligations among the numerous buyers and sellers in the California markets. At this time, we are unable to predict the timing of the completion of these proceedings or the final refund liability. The final outcome of this proceeding and the impact on our business is uncertain at this time. -8- FERC INVESTIGATION INTO WESTERN MARKETS. On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron and others used their market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether, as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. FERC has stated that it may use the information gathered in connection with the investigation to determine how to proceed on any existing or future complaint brought under Section 206 of the Federal Power Act involving long-term power contracts entered into in the West since January 1, 2000, or to initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding on its own initiative. On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies (the "Initial Report") summarizing its initial findings in this investigation. There were no findings or allegations of wrongdoing by Calpine set forth or described in the Initial Report. On March 26, 2003, the FERC staff issued a final report in this investigation (the "Final Report"). The FERC staff recommended that FERC issue a show cause order to a number of companies, including Calpine, regarding certain power scheduling practices that may have been be in violation of the CAISO's or CalPX' tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. Calpine believes that it did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material. On June 25, 2003, FERC rejected various complaints to invalidate certain long-term energy supply contracts. Also, on June 25, 2003 FERC issued a number of orders associated with these investigations, including the issuance of two show cause orders to certain industry participants. FERC did not subject Calpine to either of the show cause orders. FERC also issued an order directing the FERC Office of Markets and Investigations to investigate further whether market participants who bid a price in excess of $250 per megawatt hour into markets operated by either the CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may have violated CAISO and CalPX tariff prohibitions. No individual market participant was identified. The Company believes that it did not violate the CAISO and CalPX tariff prohibitions referred to by FERC in this order; however, we are unable to predict at this time the final outcome of this proceeding or its impact on Calpine. CPUC PROCEEDING REGARDING QF CONTRACT PRICING FOR PAST PERIODS. Our Qualifying Facilities ("QF") contracts with Pacific Gas and Electric Company ("PG&E") provide that the CPUC has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts by determining the short run avoided cost ("SRAC") energy price formula. In mid 2000, our QF facilities elected the option set forth in Section 390 of the California Public Utility Code, which provides QFs the right to elect to receive energy payments based on the California Power Exchange ("PX") market clearing price instead of the price determined by SRAC. Having elected such option, we were paid based upon the PX zonal day-ahead clearing price ("PX Price") from summer 2000 until January 19, 2001, when the PX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC at one point issued a proposed decision to the effect that the PX Price was the appropriate price for energy payments under the California Public Utility Code but tabled it, and a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. We believe that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings. THE CALIFORNIA DWR MAY ASSIGN THE DWR CONTRACTS TO ANOTHER PARTY, IN WHICH CASE WE WOULD NOT BE ENTITLED TO PAYMENTS FROM THE DWR FUND. If certain conditions are met, DWR will have the right to transfer or assign the DWR contract to another party, or to require us to enter into a replacement contract with another party, including the right to transfer the DWR contract to one or more electrical corporations (as defined under the California Water code) whose long-term unsecured senior debt is rated BBB or better by Standard and Poor's and Baa2 or better by Moody's Investor Services. In the event that the DWR contract were transferred or assigned to, or if we entered into a replacement power sales agreement with, another party, we could look for payment only to that third party, and not to DWR or the DWR Fund. We would be an unsecured creditor of that third party, and accordingly, in the event of the bankruptcy or failure to pay by that third party, we may not be able to make payments or principal or interest on the notes. -9- WE ARE SUBJECT TO COMPLEX GOVERNMENT REGULATION WHICH COULD ADVERSELY AFFECT OUR OPERATIONS. Our activities are subject to complex and stringent energy, environmental and other governmental laws and regulations. The construction and operation of power generation facilities and oil and gas exploration and production require numerous permits, approvals and certificates from appropriate foreign, federal, state and local governmental agencies, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals and permits for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations may be revised or reinterpreted, or new laws and regulations may become applicable to us that may have a negative effect on our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed facilities may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays or significant loss of value in a project. Environmental regulations have had and will continue to have an impact on our cost of doing business and our investment decisions. For example, the existing market-based cap-and-trade emissions allowance system in Texas requires operators to either reduce nitrogen oxide ("NOx") emissions or purchase additional NOx allowances in the marketplace. Rather than purchase additional allowances, we have chosen to install additional NOx emission controls as part of a $42 million steam capacity upgrade at our Texas City facility and to retrofit our Clear Lake, Texas facility with similar technology at a cost of approximately $15 million. These new emission control systems will allow us to meet our thermal customers' needs while reducing the need to purchase allowances for our facilities in Texas. Our operations are potentially subject to the provisions of various energy laws and regulations, including PURPA, the Public Utility Holding Company Act of 1935, as amended, ("PUHCA"), the FPA, and state and local regulations. PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides QFs (as defined under PURPA) and owners of QFs exemptions from certain federal and state regulations, including rate and financial regulations. The FPA regulates wholesale sales of power, as well as electric transmission in interstate commerce. Under current federal law, we are not subject to regulation as a holding company under PUHCA, and will not be subject to such regulation as long as the plants in which we have an interest (1) qualify as QFs, (2) are subject to another exemption or waiver or (3) qualify as an Exempt Wholesale Generator ("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility must be not more than 50% owned by one or more electric utility companies or electric utility holding companies. Generally, any geothermal power facility which produces up to 80MW of electricity and meets PURPA ownership requirements is considered a QF. In addition, a QF that is a cogeneration facility, such as the plants in which we currently have interests, must produce electricity as well as thermal energy for use in an industrial or commercial process in specified minimum proportions. The QF also must meet certain minimum energy efficiency standards. If any of the plants in which we have an interest lose their QF status or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded QFs, we could become a public utility holding company, which could subject us to significant federal, state and local regulation, including rate regulation. If we become a holding company, which could be deemed to occur prospectively or retroactively to the date that any of our plants loses its QF status, all our other power plants could lose QF status because, under FERC regulations, a QF cannot be owned by an electric utility or electric utility holding company. In addition, a loss of QF status could, depending on the particular power purchase agreement, allow the power purchaser to cease taking and paying for electricity or to seek refunds of past amounts paid and thus could cause the loss of some or all contract revenues or otherwise impair the value of a project. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. Such events could adversely affect our ability to service our indebtedness, including our senior notes. Currently, Congress is considering proposed legislation that would repeal PUHCA and amend PURPA by limiting its mandatory purchase obligation to existing contracts. In light of the circumstances in California, the PG&E bankruptcy and the Enron Corp. bankruptcy, among other events in recent years, there are a number of federal legislative and regulatory initiatives that could result in changes in how the energy markets are regulated. We do not know whether this -10- legislation or regulatory initiatives will be adopted or, if adopted, what form they may take. We cannot provide assurance that any legislation or regulation ultimately adopted would not adversely affect our existing domestic projects. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities' transmission and distribution systems for independent power producers and electricity consumers. However, in light of the circumstances in the California power markets and the bankruptcies of both PG&E and Enron, the pace and direction of further deregulation at the state level in many jurisdictions is uncertain. FEDERAL POWER ACT REGULATION Under the FPA, contracts for the wholesale sale of electric power, including our California DWR contracts, are subject to the jurisdiction of FERC. The sale at wholesale of electric power at market-based or negotiated rates requires the seller to have market-based rate authorization issued by FERC. FERC grants such market-based rate authorization based on several criteria, including a showing that the applicant lacks market power in generation and transmission, cannot erect other barriers to market entry, and that there is no opportunity for abusive transactions involving regulated affiliates of the applicant. Although several our direct and indirect subsidiaries, including CES, have received market-based rate authorizations from FERC, these authorizations could be revoked if we fail in the future to continue to satisfy the applicable criteria, or if FERC modifies the relevant criteria, or if FERC eliminates or restricts the ability of wholesale sellers of power to make sales at market-based and negotiated rates. There is pending before FERC a generic proceeding that proposes to condition market-based rate authority upon the seller not exercising market power or engaging in anticompetitive behavior, with refunds and other unnamed remedies imposed on violators. We cannot predict if or when FERC will finalize this initiative or what effect it may have on us. FERC also requires sellers making market-based sales to file electronic quarterly reports of their respective contract and transaction data. For those entities in which we have an interest that are EWGs with market-based rate authority, FERC has authority over our issuance of securities and our assumption of liabilities of another party. FERC has granted certain of our direct and indirect subsidiaries, including CES, blanket authority for any future security issuances and assumptions of liability. For such subsidiaries, in the event that our market-based rate authority from FERC were to be revoked, any further security issuances or assumptions of liability by us may require pre-approval by FERC. FERC regulations implementing PURPA provide that a QF is exempt from regulation under the foregoing provisions of the FPA. An EWG is not exempt from the FPA and therefore an EWG that makes sales of electric energy at wholesale in interstate commerce is subject to FERC regulation as a public utility. However, many of the regulations which customarily apply to traditional public utilities have been waived or relaxed for power marketers, EWGs and other non-traditional public utilities that lack market power. EWGs are regularly granted authorization to charge market-based rates, blanket authority to issue securities, and waivers of certain FERC requirements pertaining to accounts, reports and interlocking directorates. Such action is intended to implement FERC's policy to foster a more competitive wholesale power market. Many of the generating projects in which we own an interest are operated as QFs and are therefore exempt from FERC regulation under the FPA. However, several of our generating projects are or will be EWGs subject to FERC jurisdiction under the FPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and to issue securities, and have also been granted the customary waivers of FERC regulations available to non-traditional public utilities; however, we cannot assure that such authorities or waivers will be granted in the future to other affiliates. WE DEPEND ON OUR MANAGEMENT AND EMPLOYEES. Our success is largely dependent on the skills, experience and efforts of our people. While we believe that we have excellent depth throughout all levels of management and in all key skill levels of our employees, the loss of the services of one or more members of our senior management or of numerous employees with critical skills could have a negative effect on our business, financial conditions and results of operations and future growth. SEISMIC DISTURBANCES COULD DAMAGE OUR PROJECTS. Areas where we operate and are developing many of our geothermal and gas-fired projects are subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. Our existing power generation facilities are built to withstand relatively significant levels of seismic disturbances, and we believe we maintain adequate insurance protection. However, earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of serious seismic disturbances. Additionally, insurance for these risks may not continue to be available to us on commercially reasonable terms. -11- OUR RESULTS ARE SUBJECT TO QUARTERLY AND SEASONAL FLUCTUATIONS. Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including: o seasonal variations in energy prices; o variations in levels of production; o the timing and size of acquisitions; and o the completion of development projects. Additionally, because we receive the majority of capacity payments under some of our power sales agreements during the months of May through October, our revenues and results of operations are, to some extent, seasonal. USE OF PROCEEDS OF THE OFFERING - ------------------------------- We estimate that the net proceeds from (1) this offering of notes, (2) the $750 million of new term loans and (3) our new senior secured credit facility will be approximately $3,224 million after deducting net transaction expenses. We intend to use these proceeds for the repayment of approximately $1.4 billion on our existing senior secured credit facilities and the balance of the proceeds for general corporate purposes, including the retirement of portions of our outstanding securities, either in open-market purchases or in privately negotiated transactions, and to finance exploration, drilling, development, construction or purchase of or by, or repairs, improvements or additions to, property or assets of certain of Calpine's subsidiaries, all in accordance with the terms and provisions of Calpine's credit facilities and indentures. The following table illustrates the estimated sources and uses of funds for the proceeds of this offering and concurrent financing transactions: Amount ----------- (Dollars in millions) SOURCES: Notes offered hereby ............................ $2,550 New term loans .................................. 750 New senior secured credit facility .............. -- ------ Total Sources .............................. $3,300 ====== USES: Existing revolving credit facility .............. $ 453 Existing term loan facility ..................... 950 Underwriting fees and transaction expenses ...... 76 Cost to repurchase existing debt securities ..... 505 Cash ............................................ 1,316 ------ Total Uses ................................. $3,300 ====== On June 30, 2003, we had approximately $1.4 billion outstanding under our existing senior secured credit facilities, consisting of approximately $0.5 billion outstanding under our revolving credit facility and approximately $0.9 billion outstanding under our term loan facility. Loans under these facilities bear variable interest. During the three months ended June 30, 2003, borrowings under our senior secured credit facilities were for general corporate purposes. For the three months ended March 31, 2003, the borrowings outstanding under the revolving credit facility and term loan facility bore weighted-average interest rates of 7.87% and 6.86%, respectively, per annum. Certain of the Initial Purchasers are lenders under Calpine's existing credit facilities and/or own existing debt securities of Calpine and as a result will receive significant proceeds from this offering upon repayment of amounts outstanding under those credit facilities and/or repurchase of those debt securities. FORWARD-LOOKING STATEMENTS - -------------------------- This Current Report on Form 8-K contains forward-looking statements. Such statements include those concerning the Company's expected financial performance and its strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. Investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements such as, but not limited to: (i) the timing and extent of deregulation of energy markets and the rules and regulations adopted on a transitional basis with respect thereto; (ii) the timing and extent of changes in commodity prices for energy, particularly natural gas and electricity and the impact of related -12- derivatives transactions; (iii) unscheduled outages of operating plants; (iv) unseasonable weather patterns that produce reduced demand for power; (v) systemic economic slowdowns, which can adversely affect consumption of power by businesses and consumers; (vi) commercial operations of new plants that may be delayed or prevented because of various development and construction risks, such as a failure to obtain the necessary permits to operate, failure of third-party contractors to perform their contractual obligations or failure to obtain project financing on acceptable terms; (vii) cost estimates are preliminary and actual costs may be higher than estimated; (viii) a competitor's development of lower-cost power plants or of a lower-cost means of operating a fleet of power plants; (ix) risks associated with marketing and selling power from power plants in the evolving energy market; (x) the successful exploitation of an oil or gas resource that ultimately depends upon the geology of the resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, gas administration, marketing and operational factors relating to the extraction of natural gas; (xi) the Company's estimates of oil and gas reserves may not be accurate; (xii) the effects on the Company's business resulting from reduced liquidity in the trading and power industry; (xiii) the Company's ability to access the capital markets on attractive terms or at all; (xiv) sources and uses of cash are estimates based on current expectations; actual sources may be lower and actual uses may be higher than estimated; (xv) the direct or indirect effects on the Company's business of a lowering of its credit rating (or actions it may take in response to changing credit rating criteria), including increased collateral requirements, refusal by the Company's current or potential counterparties to enter into transactions with it and its inability to obtain credit or capital in desired amounts or on favorable terms; (xvi) possible future claims, litigation and enforcement actions pertaining to the foregoing; or (xvii) other risks. -13- SIGNATURES 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 hereunto duly authorized. CALPINE CORPORATION By: /s/ Charles B. Clark, Jr. ------------------------- Charles B. Clark, Jr. Senior Vice President and Controller Chief Accounting Officer Date: July 23, 2003 -14- -----END PRIVACY-ENHANCED MESSAGE-----