UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Form 10-K

 

 

Commission file number: 1-12079

 

 

 

 

Calpine Corporation

(A Delaware Corporation)

 

I.R.S. Employer Identification No. 77-0212977

 

50 West San Fernando Street, San Jose, California 95113
717 Texas Avenue, Houston, Texas 77002
Telephone: (408) 995-5115

 

Securities registered pursuant to Section 12(b) of the Act:

None

 

Securities registered pursuant to Section 12(g) of the Act:
Calpine Corporation Common Stock, $.001 Par Value

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act):

Large accelerated filer o          Accelerated filer þ          Non-accelerated filer o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act).  Yes o     No þ

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 524,189,920 shares of common stock, par value $.001, were outstanding as of March 9, 2007.

 

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2006, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $221.9 million.

 

 

CALPINE CORPORATION AND SUBSIDIARIES
(DEBTOR-IN-POSSESSION)

FORM 10-K

ANNUAL REPORT
For the Year Ended December 31, 2006

TABLE OF CONTENTS

 

DEFINITIONS

 

The abbreviations contained in this Report have the meanings set forth below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. For clarification, such terms will not include the Canadian and other foreign subsidiaries that were deconsolidated as of the Petition Date, as a result of the filings by the Canadian Debtors under the CCAA in the Canadian Court. The term “Calpine Corporation” shall refer only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments thereto in each case as amended, restated, supplemented or otherwise modified to the date of this Report.

 

 

In addition to historical information, this report contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to: (i) the risks and uncertainties associated with our Chapter 11 and CCAA cases, including our ability to successfully reorganize and emerge from Chapter 11; (ii) our ability to implement our business plan; (iii) financial results that may be volatile and may not reflect historical trends; (iv) seasonal fluctuations of our results; (v) potential volatility in earnings associated with fluctuations in prices for commodities such as natural gas and power; (vi) our ability to manage liquidity needs and comply with financing obligations; (vii) the direct or indirect effects on our business of our impaired credit including increased cash collateral requirements in connection with the use of commodity contracts; (viii) transportation of natural gas and transmission of electricity; (ix) the expiration or termination of our PPAs and the related results on revenues; (x) risks associated with the operation of power plants including unscheduled outages; (xi) factors that impact the output of our geothermal resources and generation facilities, including unusual or unexpected steam field well and pipeline maintenance and variables associated with the waste water injection projects that supply added water to the steam reservoir; (xii) risks associated with power project development and construction activities; (xiii) our ability to attract, retain and motivate key employees; (xiv) our ability to attract and retain customers and counterparties; (xv) competition; (xvi) risks associated with marketing and selling power from plants in the evolving energy markets; (xvii) present and possible future claims, litigation and enforcement actions; (xviii) effects of the application of laws or regulations, including changes in laws or regulations or the interpretation thereof; and (xix) other risks identified in this Report. You should also carefully review other reports that we file with the SEC. We undertake no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise.

 

We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible through the Internet at that website.

 

Our reports on Forms 10-K, 10-Q and 8-K, and amendments to those reports, are available for download, free of charge, as soon as reasonably practicable after these reports are filed with the SEC, at our website at www.calpine.com. The content of our website is not a part of this Report. You may request a copy of our SEC filings, at no cost to you, by writing or telephoning us at: Calpine Corporation, 50 West San Fernando Street, San Jose, California 95113, attention: Corporate Communications, telephone: (408) 995-5115. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery.

 

OVERVIEW

 

Our Business

 

We operate in predominantly one line of business, the generation and sale of electricity and electricity-related products, through the operation of our portfolio of power generation facilities with all of our continuing operations located in the U.S. With principal offices in San Jose, California and Houston, Texas, we were established as a

corporation in 1984 and operate through a variety of divisions, subsidiaries and affiliates. As discussed further below, we and many of our subsidiaries have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. and for creditor protection under the CCAA in Canada. We are currently operating as debtors-in-possession under the protection of the U.S. and Canadian laws.

 

We focus on two efficient and clean forms of power generation: natural gas and geothermal. At December 31, 2006, we owned or leased a portfolio of 66 clean burning natural gas-fired power plants throughout the U.S. and 19 geothermal power plants in the Geysers region of northern California, with an aggregate net capacity of 25,322 MW. Additionally, we have interests in three plants in active construction and one plant in active development.

 

We employ software licensed from third parties and outsource certain software, data and support services to third parties, and we have developed in-house proprietary software systems, management techniques and other information technologies with which we operate our power generation facilities as an integrated portfolio of power generation facilities in our major markets in the U.S. We seek to optimize the profitability of our individual facilities by coordinating O&M and major maintenance schedules, as well as dispatch and fuel supply, throughout our portfolio. By centrally managing the portfolio, our sales and marketing resources are able to more efficiently operate our portfolio of power generation facilities by providing trading and scheduling services to meet delivery requirements, respond to market signals and to ensure fuel is delivered to our facilities. Central management also enables us to reduce our exposure to market volatility and improve our results. We also have developed risk management guidelines, approved by our Board of Directors, that apply to the sales, marketing, trading and scheduling processes. Market risks are monitored to ensure compliance with our risk management guidelines and to seek to minimize our exposure. Together, these capabilities, guidelines and arrangements create efficiencies and, in turn, value for the enterprise beyond operating separate, individual power generation facilities.

 

We have prepared a business plan, which was presented to the Committees, that is designed to stabilize, improve and strengthen our core power generation business and financial health and includes the potential sale of certain power plants and our turbine parts and services businesses. Among other things, the business plan projects that, after contemplated asset dispositions, we will remain one of the largest IPPs in the U.S. The business plan also contemplates that we may selectively pursue new power plant opportunities. As part of the business plan, we also intend to simplify our capital structure.

 

Chapter 11 Cases and CCAA Proceedings

 

Since the Petition Date, Calpine Corporation and 273 of its wholly owned subsidiaries in the U.S. have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, and 12 of its Canadian subsidiaries have filed for creditor protection under the CCAA in the Canadian Court. Certain other subsidiaries could file under Chapter 11 in the U.S. or for creditor protection under the CCAA in Canada in the future. The Chapter 11 cases are being jointly administered for procedural purposes only by the U.S. Bankruptcy Court under the case captioned In re Calpine Corporation et al., Case No. 05-60200 (BRL).

 

As a result of the Canadian Debtors’ filings for creditor protection under the CCAA in Canada, we deconsolidated most of our Canadian and other foreign entities as we determined that the administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors resulted in a loss of the elements of control necessary for consolidation. We fully impaired our investment in the Canadian and other foreign subsidiaries as of the Petition Date and now account for such investments under the cost method. Because our Consolidated Financial Statements exclude the financial statements of the Canadian Debtors, the information in this Report principally describes the Chapter 11 cases and only describes the CCAA proceedings where they have a material effect on our operations or where such information provides necessary background information. We continue to work with the Canadian Debtors, the monitor appointed by the Canadian Court, and the Canadian creditors to maximize economic recoveries for all interested parties.

 

The convergence of a number of factors in late 2005 precipitated our Chapter 11 and CCAA filings. Among other things, we were experiencing a tight liquidity situation due in part to our obligations to service our debt and certain of our preferred equity securities, which also imposed restrictions on our ability to raise capital through financings, asset sales or otherwise. At the same time, market spark spreads were being adversely impacted by excess capacity in certain of our energy markets, which depressed prices for energy, while prices for natural gas

reached historic highs. Higher gas prices also increased our collateral support obligations to counterparties. Also, we were unsuccessful in a litigation we brought in the Delaware Chancery Court against the collateral agent and trustees representing our First and Second Priority Notes regarding our use of certain proceeds of the sale of our oil and natural gas reserves, which resulted in our being ordered to make a cash payment to an escrow fund of more than $300 million that had already been used to purchase natural gas in storage.

 

We continue to operate our business as debtors-in-possession and will continue to conduct business for the duration of our Chapter 11 cases in the ordinary course under the protection of the Bankruptcy Courts. As part of our “first day” and subsequent motions in the Chapter 11 cases, we have obtained U.S. Bankruptcy Court approval to continue to pay critical vendors, meet our pre-petition and post-petition payroll obligations, maintain our cash management systems, collateralize certain of our gas supply contracts, enter into and collateralize trading contracts, pay our taxes, continue to provide employee benefits including an incentive compensation program, maintain our insurance programs and implement an employee severance program. In addition, the U.S. Bankruptcy Court has approved certain trading notification and transfer procedures designed to allow us to restrict trading in our common stock (and related securities) and has also provided for potentially retroactive application of notice and sell-down procedures for trading in claims against the U.S. Debtors’ estates (in the event that such procedures are approved in the future) which could negatively impact our accumulated NOLs and other tax attributes.

 

In addition, the U.S. Bankruptcy Court has approved our DIP Facility and related cash collateral and adequate assurance stipulations, which have provided us needed liquidity while the Chapter 11 cases are pending and allowed our business activities to continue. Funds borrowed under our initial $2.0 billion DIP Facility were used to repay a portion of the First Priority Notes and to pay a portion of the purchase price for the Geysers Assets, as well as to fund our operational needs. The DIP Facility letter of credit facility has been used to provide necessary credit support for our trading activities. On March 5, 2007, the U.S. Bankruptcy Court issued an opinion approving our motion to obtain a $5.0 billion Replacement DIP Facility which, if successfully completed, will refinance the existing $2.0 billion DIP Facility as well as the approximately $2.5 billion of outstanding CalGen Secured Debt. The Replacement DIP Facility may be increased to $7.0 billion under certain circumstances, and may be converted to our exit financing once we have confirmed a plan or plans of reorganization. We expect the Replacement DIP Facility to close in late March 2007.

 

Under the Bankruptcy Code, we have the exclusive right to file and solicit acceptance of a plan or plans of reorganization for a limited period of time. On December 6, 2006, the U.S. Bankruptcy Court granted our application for an extension of the period during which we have the exclusive right to file a plan or plans of reorganization from December 31, 2006, to June 20, 2007, and granted us the exclusive right until August 20, 2007, to solicit acceptance thereof, in each case allowing for the maximum period of time provided by the Bankruptcy Code.

 

As a result of our Chapter 11 filings and the other matters described herein, including uncertainties related to the fact that we have not yet had time to complete and obtain confirmation of a plan or plans of reorganization, there is substantial doubt about our ability to continue as a going concern. Our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand; (ii) our ability to generate cash from operations; (iii) the cost, duration and outcome of the restructuring process; (iv) our ability to comply with the terms of our existing DIP Facility and Replacement DIP Facility and the adequate assurance provisions of the Cash Collateral Order; and (v) our ability to achieve profitability following a restructuring. These challenges are in addition to those operational and competitive challenges that we face in connection with our business. In conjunction with our advisors, we are implementing strategies to aid our liquidity and our ability to continue as a going concern. However, there can be no assurance as to the success of such efforts.

 

Further information pertaining to our Chapter 11 cases and CCAA proceedings may be obtained through our website at www.calpine.com. Documents filed with the U.S. Bankruptcy Court and other general information about the Chapter 11 cases are available at www.kccllc.net/calpine. Certain information regarding the CCAA proceedings, including the reports of the monitor appointed by the Canadian Court, is available at the monitor’s website at www.ey.com/ca/calpinecanada. The content of the foregoing websites is not a part of this Report.

 

Restructuring

 

In 2006, we initiated a broad, comprehensive process to begin strengthening our core business activities and improving our financial health, a process which we continue to implement in 2007. This process has formed the basis of our business plan and will be instrumental in the continued development of our plan or plans of reorganization. As part of the process, we have undertaken a thorough review of each of our power generation facilities, individually and as part of our portfolio, including the existing contractual arrangements, cash flows, regional market forecasts, potential regulatory changes and other factors that may affect such facility. In addition, we are reviewing each of our business activities to determine whether to continue in or to exit from those activities. In each case, we determine whether, on a short-term or long-term basis, the project or activity constitutes a strategic fit with our core business of generating and selling electricity and electricity-related products, contributes to our financial health and satisfies our business objectives. If it does not, we will develop a course of action which may include limiting or exiting the activity, selling or otherwise disposing of the asset, restructuring it (or restructuring related contracts or financing), suspending operations or taking other actions. In general, we are required to obtain U.S. Bankruptcy Court approval of sales of assets outside the ordinary course of business, subject to certain exceptions including with respect to de minimis assets. Such sales are also subject in certain cases to U.S. Bankruptcy Court approved auction procedures.

 

As a result of our review process, we have identified certain power generation facilities and other assets for potential sale or other disposition. In other cases, we have determined that restructuring related financing or other agreements or the physical assets would make the project or activity more advantageous. As the review process continues, additional assets may be disposed of or restructured and activities limited or exited.

 

In particular, we have identified 14 power generation facilities that required close scrutiny, and we agreed that we would limit the amount of funds available to support the operations of those designated projects. As of the filing of this Report, three of the 14 designated projects have been sold, two have been turned over to the applicable owner-lessor or secured lender, and, at three of the projects, we have restructured existing agreements or reconfigured equipment such that continued operation of the facilities is merited. We continue to assess our alternatives with respect to the remaining six facilities. In addition, we completed the sale of Goldendale Energy Center and the sale of a 35% equity interest in the Russell City power generation facility, neither of which were identified as designated projects. We also identified for potential sale 15 turbines, of which we have sold 10 turbines and one partial combustion turbine unit.

 

We also determined that two subsidiaries, TTS and PSM, which provide services and parts for combustion turbine equipment, would no longer be a strategic fit within our core business. After an auction process, TTS was sold in September 2006, and we have received U.S. Bankruptcy Court approval to sell substantially all of the assets of PSM. After selling PSM, we expect to continue a contractual relationship with PSM to procure replacement parts and have rights to participate in research and development efforts. By doing so, we will maintain the benefit of a relationship with PSM while limiting the capital requirements of ownership. We have also decided to limit third-party O&M services through our subsidiary CPSI. Although CPSI will continue to perform its services under existing construction management contracts, we do not plan to execute new contracts.

 

We have also reviewed approximately 6,000 of our leases and executory contracts to determine whether they constitute a strategic fit within our core business and, if not, to evaluate whether they should be assumed, rejected, repudiated or restructured as permitted under the Bankruptcy Code. While this process is not complete, we have taken actions accordingly, including rejecting approximately 50 executory contracts and 30 real property and equipment leases. Parties to executory contracts or unexpired real property leases rejected or deemed rejected by a U.S. Debtor may file proofs of claim against that U.S. Debtor’s estate for damages, and parties to executory contracts or unexpired leases that are assumed have an opportunity to assert cure amounts prior to such assumptions.

 

Significant contract rejections include our motion, on the first day of our Chapter 11 cases, to reject eight below-market PPAs and to enjoin FERC from asserting jurisdiction over the rejections (Note 15 of the Notes to Consolidated Financial Statements contains further discussion of this matter). Since filing the motion, three of the PPAs were terminated by the applicable counterparties, and three were restructured by negotiated settlement; we continue to perform under the terms of the restructured PPAs as well as, while our rejection motion remains pending, the remaining two PPAs subject to any modifications agreed to by the parties, and we exercised our option

under one such PPA to terminate the PPA in April 2008 prior to the remaining five years of its original term. We have also rejected the Rumford and Tiverton power plant leases and surrendered the facilities to their owner-lessor, and we have closed nine offices after rejecting the related leases. In addition, we have determined that certain gas transportation and power transmission contracts no longer provide any benefit to us and, accordingly, have given notice to counterparties to these contracts that we will no longer accept or pay for services under such contracts.

 

With respect to significant contract assumptions, on June 5, 2006, the U.S. Bankruptcy Court approved our motion to assume geothermal leases related to the Geysers Assets steam field operations and the Glass Mountain Known Geothermal Resource Area, and the associated executory contracts, surface use agreements and site leases that allow the geothermal leases to be utilized to harness geothermal energy and operate existing facilities. The geothermal leases combined with the operations at the Geysers Assets constitute the core collateral for the DIP Facility. We have also assumed approximately 60 ground and facility leases related to our power plants, as well as certain office leases, pipeline leases and oil and gas leases.

 

In tandem with the review of our assets and activities as described above, we conducted an evaluation of our trading, hedging and optimization activities as they related to our portfolio of power plants and the markets within which we operate. At the beginning of our evaluation, we reduced efforts to enter into new long-term PPAs and fuel procurement contracts for existing generation plants as we developed parameters for determining the right balance among spot market sales and purchases and short-term, long-term and tolling contracts for the sale of our electric generation and fuel procurement. Throughout 2007, we will be working to optimize this mix as well as to expand the number of counterparties with whom we can trade to facilitate our contractual goals and improve our financial position.

 

With respect to our construction and development projects, until we emerge from Chapter 11, we expect to limit our expenditures on construction and development of new power generating facilities and focus our efforts on maximizing the value of our existing projects, including our three facilities under construction and one in advanced development. We continue to review our less advanced development opportunities to determine if we should begin active development or construction, and we may pursue new opportunities that arise, particularly if power contracts and financing are available and attractive returns are expected.

 

In addition to the actions discussed above, we eliminated approximately 850 full-time positions in 2006. During 2007, as we continue our comprehensive review, we expect that we will seek to limit or exit certain activities, sell power generation facilities, or we may temporarily or permanently shut down additional power generation facilities or other assets, that are not a strategic fit within our core business. In connection with these activities, we may further reduce our staffing levels in 2007.

 

We believe that these continued restructuring efforts will allow us to improve our financial strength and to successfully emerge from Chapter 11.

 

THE MARKET FOR ELECTRICITY

 

The power industry represents one of the largest industries in the U.S. and impacts nearly every aspect of our economy, with an estimated end-user market comprising approximately $323 billion of electricity sales in 2006 based on information published by EIA. Historically, the power generation industry was largely characterized by electric utility monopolies producing electricity from generating facilities owned by utilities and selling to a captive customer base. However, industry trends and regulatory initiatives have transformed some markets into more competitive arenas where load-serving entities and end-users may purchase electricity from a variety of suppliers, including IPPs, power marketers, regulated public utilities, major financial institutions and others. For over a decade the power industry has been deregulated at the wholesale level allowing generators to sell directly to the load-serving entities such as public utilities, municipalities and electric cooperatives. Although industry trends and regulatory initiatives aimed at further deregulation have slowed, halted or even reversed in some geographic regions, in terms of the level of competition, pricing mechanisms and pace of regulatory reform, two of our largest markets, California and ERCOT, have emerged as more competitive markets.

 

The U.S. market consists of distinct regional electric markets, not all of which are effectively interconnected. As a result, reserve margins (the measure of how much the total generating capacity installed in a region exceeds the

peak demand for power in that region) vary from region to region. Due primarily to the completion of more than 200,000 MW of gas-fired combustion turbine projects throughout the U.S. in the past decade, we have seen power supplies and reserve margins generally increase in the last several years, while, according to data published by EEI, the growth rate of nationwide consumption of electricity in 2006 compared to 2005 was estimated to be negative 0.1%. As a result, the excess supply could not be absorbed in the market, and we witnessed a decrease in liquidity in the energy trading markets, putting downward pressure on prices generally. Within our two major markets, EEI estimates growth rates from 2005 to 2006 of 1.0% for the South Central region (primarily Texas), and 1.2% for the Pacific Southwest (primarily California). In the wake of such aggressive supply expansion, however, the projected growth rate of additional supply has been diminishing, with many developers canceling or delaying completion of their projects as a result of current and forecasted market conditions. After such expansion is absorbed by the market, reserve margins may decrease. Some market regulators have already forecasted such conditions, including two of our major markets. For example, ERCOT has forecasted that capacity margins in ERCOT will dip below 11% in 2008. Similarly, the NERC 2006 Long-Term Reliability Assessment forecasts that summer capacity margins in WECC will decrease from 18% in 2007 to 14% in 2010, and SERC reported in July 2006 that capacity margins are expected to decline from 25% in 2007 to 23% in 2010 based on generation and interconnection agreements signed or filed.

 

Moreover, in various regional markets, electricity market administrators have acknowledged that the markets for generating capacity do not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage new generating capacity to be constructed. Capacity auctions are being implemented in the Northeast and Mid-Atlantic regional markets to address this issue. If the auctions are successful, and if other markets adopt this approach, it could provide significant additional capacity revenues for IPPs, but any such new capacity market could take years to develop.

 

COMPETITION

 

We compete against other IPPs, trading companies, financial institutions, retail load aggregators, municipalities, retail electric providers, cooperatives and regulated utilities to supply electricity and electricity-related products to our customers in major markets nationwide. In some markets, we compete against some of our own customers. During recent years, financial institutions have aggressively entered the market. However, we believe the addition of financial institutions to the market has been beneficial by increasing the number of customers for our physical power products, offering risk management products to manage commodity price risk, improving the general financial strength of market participants and ultimately increasing liquidity in the markets. To a large extent, market competition is influenced by the degree of deregulation. We believe that deregulated markets, where there are more participants buying and selling, are generally more competitive and lead to lower prices.

 

Generally, pricing can be influenced by a variety of factors, including the following:

 

 

In deregulated markets, our natural gas and geothermal facilities compete directly with all other sources of electricity. Even though most new power generating facilities are fueled by natural gas, EIA estimates that only 21% of the electricity generated in the U.S. is fueled by natural gas and that nearly two-thirds of power generated in the U.S. is still produced by coal and nuclear facilities, which generate approximately 49% and 19%, respectively. EIA estimates that the remaining 11% of electricity generated in the U.S. is fueled by hydro, fuel oil and other sources. However, as environmental regulations continue to evolve, the proportion of electricity generated by natural gas and other low emissions resources is expected to increase in some markets. Some states are imposing strict environmental standards on generators that limit emissions of GHG. As a result, many of the current coal plants will likely have to install a significant amount of costly emission control devices or limit their operations. Meanwhile, many states are mandating that certain percentages of electricity delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind and solar energy. This activity could cause some coal plants to be retired, thereby allowing a greater proportion of power to be produced by facilities fueled by natural gas, geothermal or other resources that result in lower environmental impact.

 

MARKETING, HEDGING, OPTIMIZATION AND TRADING ACTIVITIES

 

Most of the electricity generated by our facilities is scheduled and settled by our marketing and risk management unit, which sells to load-serving entities such as utilities, municipalities, cooperatives, retail electric providers, commercial and industrial end users, financial institutions, power trading and marketing companies and other third parties. We enter into physical and financial purchase and sale transactions as part of our hedging, balancing and optimization activities. The hedging, balancing and optimization activities are designed to protect or enhance our spark spread. For more information on spark spreads, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operating Performance Metrics.”

 

Our hedging, balancing and optimization activities are directly related to risk exposures that arise from our ownership and operation of power plants and our open gas positions. We are one of the largest consumers of natural gas in North America entering into transactions of approximately 564.4 bcf during 2006. We employ a portfolio of transactions to satisfy most of our natural gas fuel requirements from the market. We enter into natural gas storage and transport agreements to achieve delivery flexibility and to enhance our optimization capabilities. We constantly evaluate our natural gas needs in real time, adjusting our natural gas position to maximize profits within the limitations prescribed in our commodity risk policy.

 

We utilize derivatives, including many physical commodity contracts and commodity financial instruments such as exchange-traded swaps and forward contracts, to optimize the returns from our power plants and open gas positions and to hedge our exposures to energy commodity price risk. From time to time, we enter into contracts considered energy trading contracts for similar purposes.

 

We have value at risk limits that govern the overall risk of our portfolio of plants, energy trading contracts, financial hedging transactions and other contracts. Our value at risk limits, transaction approval limits and other limits are dictated by our commodity risk policy which is approved by our Board of Directors and administered by our Chief Risk Officer and his organization. The Chief Risk Officer’s organization is segregated from the marketing and risk management unit, and reports directly to our Audit Committee and Chief Executive Officer. Our risk management policies limit our hedging activities to protect and optimize the value of our physical assets, while limiting purely speculative hedging transactions. While this policy limits our potential upside from hedging activities, it also provides us a degree of protection from any significant downside from our hedging activities.

 

Seasonality and weather have a significant impact on our results of operations and are also considered in our hedging and optimization activities. Most of our generating facilities are located in regional electric markets where the greatest demand for electricity occurs during the summer months, in our fiscal third quarter. Depending on existing contract obligations and forecasted weather and electricity demands, we may maintain either a larger or smaller open position on fuel supply and committed generation during the summer months so that we can enhance or protect our spark spreads accordingly.

 

STRATEGY

 

We strive to offer reliable, flexible and environmentally friendly electricity and electricity-related products to the market at competitive prices.

 

We believe that our portfolio of power generating facilities allows us to offer uniquely flexible, highly structured products designed to meet our customers’ specific needs. Unlike marketers who do not own generation facilities, we can offer electricity and electricity-related products from specific facilities that are within geographic areas with special needs. We can also sell varying quantities of electricity during on-peak and off-peak hours or winter and summer months, and we can offer option products whereby customers can request additional quantities within established parameters. Additionally, our newer, more efficient combustion turbines are capable of faster starts than turbines based on older technology, which increases our flexibility in designing products for our customers.

 

By centrally managing our portfolio of power generating facilities, we can offer a high level of reliability to our customers which increases the value of our products. Through our own proprietary software systems and management techniques, we coordinate the O&M and major maintenance schedules, as well as dispatch and fuel supply, throughout our portfolio. This portfolio approach allows us to capitalize on arbitrage opportunities. For instance, in the event that one of our facilities is unavailable in a particular market, we might call upon another of our facilities in the same market to generate the electricity promised to a customer. Such coordination has allowed us to achieve a high level of reliability.

 

Through our restructuring activities, we intend to focus on those activities that offer a strategic fit with our core business and expect that centrally managing our portfolio of power plants will further enable us to offer highly flexible and reliable products to our customers at competitive prices, while our hedging, balancing and optimization activities will protect and enhance our spark spreads. Together, we believe these factors will enable us to successfully emerge from Chapter 11 as a leading IPP.

 

SIGNIFICANT CUSTOMER

 

See Note 2 of the Notes to Consolidated Financial Statements for a discussion of sales in excess of 10% of our total revenues to one of our customers.

 

ENVIRONMENTAL STEWARDSHIP

 

We were founded on the principle that a strong commitment to the environment is inextricably linked to excellence in power generation and responsible corporate citizenship. Since our founding, more than two decades ago, we have had an unwavering commitment to clean, cost-effective, energy-efficient and renewable power generation technologies. Our commitment to environmental stewardship in power generation allows us to help meet the needs of a growing economy that demands more and cleaner sources of electricity.

 

As of December 31, 2006, we had the capacity to deliver 25,322 MW of clean, reliable electricity to customers and communities in 20 states, enough electricity to power nearly 20 million homes. We own and operate one of the country’s largest fleets of combined-cycle natural gas-fired generation facilities, and we are the nation’s largest renewable geothermal power producer.

 

Our fleet of modern, combined-cycle natural gas-fired power generation facilities is highly efficient. These facilities consume significantly less fuel to generate electricity than older boiler/steam turbine power generation facilities and emit less air pollution into the environment per unit of electricity produced as compared to coal-fired or oil-fired power generation facilities. All of our natural gas-fired power generation facilities have air emissions controls, and most have selective catalytic reduction to further reduce emissions of nitrogen oxides, a known precursor of atmospheric ozone.

 

The table below summarizes approximate air pollutant emission rates from our combined-cycle natural gas-fired power generation facilities compared to the average emission rates from U.S. coal, oil and gas-fired power plants as a group.

 

 

 

 

Our 725-MW fleet of geothermal power generation facilities utilizes a natural, clean and renewable energy source — steam from the earth’s interior — to generate electricity. Since these facilities do not burn fossil fuel, they are able to produce electricity with negligible air emissions. Compared to the average U.S. coal-, oil-, and gas-fired power generation facility, our geothermal facilities emit 99.9% less NOx and SO₂ and 96.4% less CO₂. In addition, these geothermal facilities feature add-on controls to remove sulfur and mercury from air emissions.

 

Today, we own and operate 19 of the 21 power generation facilities located in the Geysers region of northern California. We recognize the importance of our geothermal facilities, and we are committed to extending, and possibly expanding, this renewable geothermal resource through wastewater recharge projects where clean, reclaimed wastewater from local municipalities is recycled into the geothermal resource where it is converted into steam for electricity production.

 

Policymakers at the federal, regional and state levels are advancing legislation to address the impact on the climate of man-made CO₂ emissions. The generation of electricity is the largest single source of man-made CO₂ emissions in the U.S., and, as such, one of the fastest ways to reduce CO₂ emissions is by replacing the nation’s aging fleet of fossil fuel-fired plants with modern, cost-effective, highly efficient combined-cycle, natural gas-fired power generation facilities and more renewable power generation.

 

We are committed to maintaining our fleet of clean, cost-effective and efficient power generation facilities and to the reduction of CO₂ emissions. We also are committed to supporting policymakers on legislation to reduce emissions. In 2006, we were involved in the development and enactment of California’s landmark global warming legislation, AB 32. In January 2007, we publicly supported legislation introduced by Senator Dianne Feinstein aimed at reducing greenhouse gas emissions from the electric power sector.

 

We have implemented a program of proprietary operating procedures to reduce gas consumption and lower air pollutant emissions per MWh of electricity generated. Thermal efficiency improvements in our fleet operations

reduced CO₂ emissions by approximately 234,000 tons in 2005 compared to 2004. Our environmental record has been widely recognized.

 

 

DESCRIPTION OF POWER GENERATION FACILITIES

 

Plants in Operation or Construction at December 31, 2006:

 

 

 

 

At December 31, 2006, we had ownership or lease interests in 85 operating power generation facilities representing 25,322 MW of net capacity. Of these projects, 66 are gas-fired power generation facilities with a net capacity of 24,597 MW, and 19 are geothermal power generation facilities with a net capacity of 725 MW. Our average baseload capacity in operations, which excludes peaker facilities, increased by 7.1% to 23,820 MW in 2006 from 22,242 MW in 2005. However, actual baseload generation declined by 4.5% to 81.7 million MWh in 2006 from 85.5 million MWh in 2005, and our 2006 baseload capacity factor declined to 39.2% in 2006 from 43.9% in 2005. The decline in generation and baseload capacity factor was due to weakness in demand in the first and second quarters of 2006 in particular, primarily as a result of generally mild weather in our major markets and strong hydroelectric generation in the West. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operating Performance Metrics” for additional information on average baseload capacity factor. We also have three new gas-fired projects currently under construction with a projected net capacity of 1,332 MW. Each of the power generation facilities currently in operation is capable of producing electricity for sale to a utility, other third-party end user or an intermediary such as a marketing company. Thermal energy (primarily steam and chilled water) produced by the gas-fired cogeneration facilities is sold to industrial and governmental users. As discussed in “Overview — Restructuring” above, we may seek to sell certain of these facilities over the next year.

 

Our gas-fired and geothermal power generation projects produce electricity and thermal energy that is sold pursuant to short-term and long-term PPAs or into the spot market. Revenue from a PPA often consists of either energy payments or capacity payments or both. Energy payments are based on all or a portion of a power plant’s net electrical output, and payment rates are typically either at fixed rates or are indexed to market averages for energy or fuel. Capacity payments are based on all or a portion of the amount of MW that a power plant is capable of delivering at any given time. Energy payments are earned for each MWh of energy delivered. Capacity payments are typically earned whether or not any electricity is scheduled by the customer and delivered; however, capacity typically has an availability requirement.

 

We currently lease geothermal steam fields in the Geysers region in northern California from which we extract steam for our geothermal power generation facilities. We have leasehold interests in 104 leases comprising approximately 25,826 acres of federal, state and private geothermal resource lands in the Geysers region in northern California. In the Glass Mountain and Medicine Lake areas in northern California, we hold leasehold interests in 41 leases comprising approximately 46,400 acres of federal geothermal resource lands. In general, under these leases, we have the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. The leases are generally for initial terms varying from 10 to 20 years or for so long as

geothermal resources are produced and sold. Certain of the leases contain drilling or other exploratory work requirements. In certain cases, if a requirement is not fulfilled, the lease may be terminated and in other cases additional payments may be required. We believe that our leases are valid and that we have complied with all the requirements and conditions material to the continued effectiveness of the leases. See Note 15 of the Notes to Consolidated Financial Statements for a description of litigation relating to our Glass Mountain and Medicine Lake area leases. A number of our leases for undeveloped properties may expire in any given year. Before leases expire, we perform geological evaluations in an effort to determine the resource potential of the underlying properties. We can make no assurance that we will decide to renew any expiring leases. We inject waste water from the City of Santa Rosa Recharge Project and from Lake County into our geothermal reservoirs. We expect the injected water to extend the useful life of this resource, which is depleted over time, and enhance the output of our geothermal resources and power plants.

 

Upon completion of our projects under construction, subject to any dispositions that may occur, we will provide O&M services for all but two of the power plants in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, and gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operating and maintenance manuals for each power generation facility that we operate. As a facility develops an operating history, we analyze its operation and may modify or upgrade equipment or adjust operating procedures or maintenance measures to enhance the facility’s reliability or profitability.

 

Certain power generation facilities in which we have an interest have been financed primarily with project financing that is structured to be serviced out of the cash flows derived from the sale of electricity (and, if applicable, thermal energy and capacity payments) produced by such facilities and generally provides that the obligations to pay interest and principal on the loans are secured solely by the capital stock or partnership interests, physical assets, contracts and/or cash flow attributable to the entities that own the facilities. The lenders under these project financings generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the facilities. Certain of these facilities have filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code; however, we do not, at this time, consider the non-recourse debt related to these U.S. Debtor entities to be subject to compromise.

 

Substantially all of the power generation facilities in which we have an interest are located on sites which we own or lease on a long-term basis.

 

Set forth below is certain information regarding our operating power plants and plants under construction as of December 31, 2006.

 

Power Plant Portfolio Summary

 

Power Plants in Operation and under Construction

 

 

 

 

 

 

Projects Under Active Construction (All Gas-Fired) at December 31, 2006

 

The development and construction of power generation projects involves numerous elements, including evaluating and selecting development opportunities, designing and engineering the project, obtaining PPAs in some cases, acquiring necessary land rights, permits and fuel resources, obtaining financing, procuring equipment and managing construction. We intend to focus on completing the projects discussed below that are already in

construction, while construction on certain other projects may remain in suspension or the projects may be sold. We generally do not expect to start development or construction on new projects at least until after we have developed our plan of reorganization; however, in certain cases exceptions may be made if power contracts and financing are available and attractive returns are expected.

 

Otay Mesa Energy Center.  In July 2001, we acquired OMEC and the associated development rights including a license permitting construction of the plant from the CEC. Site preparation activities for this 593-MW facility, located in southern San Diego County, California began in 2001. In February 2004, we signed a ten-year PPA with SDG&E for delivery of up to 615 MW of capacity and energy beginning January 1, 2008. In February 2006, SDG&E notified us that it was terminating the original PPA, and at that time we began negotiations regarding the reinstatement of the PPA with certain modifications. In October 2006, we entered into a PPA Reinstatement Agreement and an Amended and Restated PPA with SDG&E. Power deliveries under the contract are now scheduled to begin on May 1, 2009. At the end of the ten-year PPA term, OMEC has an option to require SDG&E to purchase the plant and SDG&E has an option to require OMEC to sell the plant to SDG&E. Construction of this facility has proceeded only gradually while we have sought certain regulatory approvals and, more recently, as a result of the negotiations with SDG&E.

 

Freeport Energy Center.  In May 2004, we announced plans to build and own a 236-MW, natural gas-fired cogeneration power plant in Freeport, Texas. Under a 25-year agreement, nominally 186 MW of electricity and 1,000,000 pounds per hour of steam generated at the facility will be sold to Dow Chemical Co. in Freeport, Texas. Dow Chemical Co. will operate this facility. Construction of the facility began in June 2004. Commercial operations commenced in multiple phases, with the first phases completed in January 2006 and the last phase in early 2007.

 

Greenfield Energy Centre.  In April 2005, we announced, together with Mitsui, an intention to build, own and operate a 1,005-MW, natural gas-fired power plant located in Ontario, Canada. The facility will deliver electricity to the OPA under a 20-year PPA. We contributed three combustion turbines, three combustion generators, one steam turbine generator, and cash to the project, giving us a 50% interest in the facility. Mitsui owns the remaining 50% interest. Construction began in November 2005, and commercial operation is expected to occur in the first quarter of 2008.

 

Projects Under Active Development at December 31, 2006

 

Russell City Energy Center.  A proposed 600-MW, natural gas-fired power plant to be located in Hayward, California, the Russell City Energy Center will deliver its full output to PG&E under a PPA which was executed in December 2006 and approved by the CPUC in January 2007. In September 2006, we sold a 35% equity interest in the project to ASC for approximately $44 million and ASC’s obligation to post a $37 million letter of credit. We own the remaining 65% interest. ASC’s equity will be applied toward completion of development and construction of the power plant, and ASC will also provide related credit support for the project. Construction is scheduled to begin in the spring of 2008, and commercial operation is expected to occur in June 2010.

 

GOVERNMENT REGULATION

 

We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our energy generation facilities and in connection with the purchase and sale of electricity and natural gas. Federal laws and regulations govern, among other things, transactions by electric and gas companies, the ownership of these facilities and access to and service on the electric transmission grid and natural gas pipelines.

 

There have been a number of federal and state legislative and regulatory actions that have recently changed, and will continue to change, how our business is regulated. Such changes could adversely affect our existing business.

 

Federal Regulation of Electricity

 

Electric utilities have been highly regulated by the federal government since the 1930s, principally under the FPA and PUHCA 1935. These statutes have been amended and supplemented by subsequent legislation, including the PURPA, the EPAct 1992 and the EPAct 2005. Over the past year, many of the changes made by EPAct 2005 have

been implemented or are currently in the process of being implemented through new FERC regulations. These particular statutes and regulations are discussed in more detail below.

 

FERC Jurisdiction

 

The FPA grants the federal government broad authority over electric utilities and IPPs, and vests its authority in FERC. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of electricity in interstate commerce is a public utility subject to FERC’s jurisdiction. FERC governs, among other things, the disposition of certain utility property, the issuance of securities by public utilities, the rates, terms and conditions for the transmission or wholesale sale of electric energy in interstate commerce, interlocking directorates and the uniform system of accounts and reporting requirements for public utilities.

 

The majority of our generating projects are subject to FERC’s jurisdiction, but some qualify for available exemptions. FERC’s jurisdiction over EWGs under the FPA applies to the majority of our generating projects because they are EWGs or are owned by EWGs, except our EWGs located in ERCOT. Facilities located in ERCOT are exempt from many FERC regulations under the FPA. Many of the generating facilities in which we own an interest that are not EWGs are operated as QFs under PURPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been granted certain waivers of FERC reporting and accounting regulations available to non-traditional public utilities; however, we cannot assure that such authorities or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.

 

FERC Regulation of Market-Based Rates

 

Under the FPA and FERC’s regulations, the wholesale sale of power at market-based or cost-based rates requires that the seller have authorization issued by FERC to sell power at wholesale pursuant to a FERC-accepted rate schedule. FERC grants market-based rate authorization based on several criteria, including a showing that the seller and its affiliates lack market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. All of our affiliates that own domestic power plants (except for some of those power plants that are QFs under PURPA, or those that are located in ERCOT), as well as our power marketing companies (MBR Companies), are currently authorized by FERC to make wholesale sales of power at market-based rates. This authorization could possibly be revoked for any of our MBR Companies, if they fail to continue to satisfy FERC’s current or future criteria, or if FERC eliminates or restricts the ability of wholesale sellers of power to make sales at market based rates.

 

FERC’s regulations specifically prohibit the manipulation of the electric energy markets by making it unlawful for any entity, in connection with the purchase or sale of electricity, or the purchase or sale of electric transmission service under FERC’s jurisdiction, to engage in fraudulent or deceptive practices.

 

To ward against market manipulation, FERC requires us and other sellers making sales pursuant to their market-based rate authority to file certain reports, including quarterly reports of contract and transaction data, notices of any change in status and triennial updated market power analyses. If a seller does not timely file these reports or notices, FERC can revoke the seller’s market-based rate authority. FERC’s regulations also contain four market behavior rules that apply to sellers with market-based rate authority. These rules address such matters as compliance with organized RTO or ISO market rules, communication of accurate information, price reporting to publishers of electricity or natural gas price indices and record retention. Failure to comply with these regulations can lead to sanctions by FERC, including penalties and suspension or revocation of market-based rate authority.

 

FERC Regulation of Transfers of Jurisdictional Facilities

 

Dispositions of our jurisdictional facilities or certain types of financing arrangements may require prior FERC approval, which could result in revised terms or impose additional costs, or cause a transaction to be delayed or terminated. Pursuant to Section 203 of the FPA, as amended by EPAct 2005, a public utility must obtain authorization from FERC before the public utility is permitted to: sell, lease or dispose of FERC-jurisdictional facilities with a value in excess of $10 million; merge or consolidate facilities with those of another entity; or acquire any security or securities with a value in excess of $10 million issued by another public utility. FERC’s prior

approval is also required for transactions involving certain transfers of existing generation facilities and certain holding companies’ acquisitions of facilities with a value in excess of $10 million. FERC’s regulations implementing Section 203 provide blanket authorizations for certain types of transactions, including acquisitions by holding companies that are holding companies solely due to their ownership, directly or indirectly, of one or more QFs, EWGs and FUCOs, of the securities of additional QFs, EWGs and FUCOs without FERC prior approval.

 

FERC Regulation of Open Access Electric Transmission

 

We do not own transmission facilities and are therefore dependent on the use of others’ transmission facilities to reach our customers. FERC’s Order Nos. 888 and 889 require the adoption of FERC’s pro forma Open Access Transmission Tariff establishing terms of non-discriminatory transmission service. Many non-jurisdictional transmission owners also voluntarily provide open access to their transmission systems through reciprocity provisions. Order No. 889 requires transmission-owning utilities to provide the public with an electronic system for buying and selling transmission capacity in transactions with the utilities and abide by specific standards of conduct when using their transmission systems to make wholesale sales of power.

 

FERC recently issued a final rule, Order No. 890, which revises its open access rules under the Order No. 888 pro forma Open Access Transmission Tariff to reflect FERC’s and the electric utility industry’s experience with open access transmission over the last decade. We do not know at this time what impact this final rule will have on our business.

 

In addition to FERC’s Open Access efforts under Order Nos. 888, 889 and 890, our business may be affected by a variety of other FERC policies and proposals, such as the voluntary formation of RTOs. FERC’s policies and proposals will continue to evolve, and FERC may amend or revise them, or may introduce new policies or proposals in the future. The impact of such policies and proposals on our business is uncertain and cannot be predicted at this time.

 

FERC Regulation of Books and Records

 

Under PUHCA 2005, which was promulgated in EPAct 2005 and supersedes PUHCA 1935 effective as of February 8, 2006, FERC has the right to review books and records of “holding companies,” as defined in PUHCA 2005, that are determined by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are considered a holding company, as defined in PUHCA 2005, by virtue of our control of the outstanding voting securities of our subsidiaries that own or operate facilities used for the generation of electric energy for sale or that are themselves holding companies. However, we are exempt from FERC’s inspection rights pursuant to one of the limited exemptions under PUHCA 2005 because we are a holding company due solely to our owning one or more QFs, EWG and FUCOs.

 

Similarly, EPAct 2005 also subjects “holding companies” and “associate companies” within a “holding company system” each as defined in EPAct 2005, other than holding companies that are holding companies due solely to their owning one or more QFs, to certain state commission rights of access to certain of the companies’ books and records if the state commission has jurisdiction to regulate a “public-utility company,” as defined in EPAct 2005, within that holding company system. We cannot predict what effect this part of EPAct 2005 and state regulations implementing it may have on our business. However, section 201(g) of the FPA already provides state commissions with access to books and records of certain electric utility companies subject to the state commission’s regulatory authority, EWGs that sell power to such electric utility companies, and any electric utility company, or holding company thereof, which is an associate company or affiliate of such EWGs. If any single Calpine entity were not a QF, EWG or FUCO, then we and our holding company subsidiaries would be subject to the books and records access requirement.

 

FERC Regulation of Qualifying Facilities

 

PURPA, prior to its amendment by EPAct 2005, and the new regulations adopted by FERC, provided certain incentives for electric generators whose projects satisfy FERC’s criteria for QF status. As recognized under FERC’s regulations, most QF generators were exempt from regulation under PUHCA 1935, most provisions of the FPA and most state laws and regulations.

 

To be a QF, a cogeneration facility must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility’s total energy output, and must meet certain efficiency standards. A geothermal small power production facility may qualify as a QF if, in most cases, its generating capability does not exceed 80 MW. Finally, PURPA required that no more than 50% of the equity of a QF could be owned by one or more electric utilities or their affiliates.

 

EPAct 2005 and FERC’s implementing regulations have eliminated certain benefits of QF status. FERC has eliminated the exemption from sections 205 and 206 of the FPA for a QF’s wholesale sales of power made at market-based rates. Under FERC’s new regulations, our QFs have obtained or will have to obtain market-based rate authorization for wholesale sales that are made pursuant to a contract executed after March 17, 2006, and not under a state regulatory authority’s implementation of section 210 of PURPA. In addition, new cogeneration QFs desiring to avail themselves of a utility’s mandatory purchase obligations (if any) will be required to demonstrate that their thermal, chemical, electrical and mechanical output will be used primarily for industrial, commercial, residential or institutional purposes.

 

EPAct 2005 also amends PURPA to eliminate, on a prospective basis, the mandatory obligation of an electric utility to purchase power from QFs at the utility’s avoided cost, to the extent FERC determines that such QFs have access to a competitive wholesale electricity market. This amendment does not change a utility’s obligation to purchase power at the rates and terms in pre-existing QF PPAs. On October 20, 2006, FERC issued a final rule to implement this provision from EPAct 2005. The order establishes a rebuttable presumption that any utility located in MISO, PJM, NE-ISO, NYISO or ERCOT will be relieved from the must-buy requirement with respect to QFs larger than 20 MW. With respect to other markets, and with respect to all QFs 20 MW or smaller, the utility bears the burden of showing that it qualifies for relief from the must-buy requirement. Any electric utility seeking relief from the must-buy requirement, regardless of location, must apply to FERC for relief. We cannot predict at this time what impact this rule will have on our business.

 

While we cannot predict what effect other provisions of EPAct 2005 and FERC’s regulations implementing them may have on our business at this time, we believe that each of the facilities in which we own an interest and which operates as a QF meets the current requirements for QF status. Certain factors necessary to maintain QF status are, however, subject to the risk of events outside our control. For example, some of our facilities have temporarily been rendered incapable of meeting such requirements due to the loss of a thermal energy customer and we have obtained limited waivers (for up to two years) of the applicable QF requirements from FERC. We cannot provide assurance that such waivers will in every case be granted.

 

Additional Provisions of EPAct 2005

 

EPAct 2005 enhanced FERC’s enforcement authorities by: (i) expanding FERC’s civil penalty authority to cover violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder; (ii) establishing the maximum civil penalty FERC may assess under the NGA or Part II of the FPA as $1,000,000 per violation for each day that the violation continues and (iii) expanding the scope of the criminal provisions of the FPA by increasing the maximum fines and increasing the maximum imprisonment time. Accordingly, in the future, violations of the FPA and FERC’s regulations could potentially have more serious consequences than in the past.

 

Regional Regulation

 

The following summaries of the regional rules and regulations affecting our business focus on the Western and ERCOT regions because these are the regions in which we have the most significant portfolios of assets. While we provide a brief overview of the primary regional rules and regulations affecting our facilities located in other regions of the country, we do not provide an in-depth discussion of these rules and regulations because our asset portfolio in those regions is not significant. All facility and MW data is reported as of December 31, 2006.

 

Western Region

 

Our subsidiaries own 47 generating facilities (including one facility under construction) with the capacity to generate a total of 8,086 net MW in the WECC region, which extends from the Rocky Mountains westward. The

majority of these facilities are located in California, in the CAISO control area. We also own generating facilities in Arizona, Colorado, Oregon and Washington.

 

While CAISO manages the transmission lines, the transmission lines themselves are owned by individual utilities such as PG&E and Southern California Edison Company. CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within California and providing open, nondiscriminatory transmission services. Pursuant to a FERC-approved tariff, CAISO has certain abilities to impose penalties on market participants for violations of its rules. CAISO maintains various markets for wholesale sales of electricity, differentiated by time and type of electrical service, into which our subsidiaries may sell electricity from time to time. These markets are subject to various controls, such as price caps and mitigation of bids when reference prices are exceeded. The controls and the markets themselves are subject to regulatory change at any time.

 

On September 21, 2006, FERC issued an order approving the CAISO’s MRTU proposal. The MRTU is a comprehensive redesign of all CAISO operations currently slated to go into effect March 2008. Under MRTU, the CAISO will run a new integrated day-ahead market for energy and ancillary services as well as a real-time market and an hour-ahead scheduling protocol. The energy market will change from a zonal to a nodal market. The primary features of a nodal market include a centralized, day-ahead market for energy, nodal transmission congestion management model that results in locational marginal pricing at each generation location, financial congestion hedging instruments and centralized day-ahead commitment process. Given the comprehensiveness of the market design, with features that may prove to be both positive and negative for energy sellers, we cannot predict at this time what impact MRTU will have on our business.

 

Our plants located outside of California either sell power into the markets administered by CAISO or sell power through bilateral transactions outside CAISO. Those transactions occurring outside CAISO are subject to FERC regulation and oversight, but they are not subject to CAISO rules and regulations.

 

Texas Region

 

Our subsidiaries own 12 natural gas-fired generating facilities (including one facility under construction as of December 31, 2006) in the Texas region with the total capacity to generate 7,510 net MW, all of which are physically located in the ERCOT market. ERCOT is an ISO that manages approximately 85% of Texas’ power market and an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail electric market. The remainder of the Texas market is part of SPP, SERC and WECC. FERC does not regulate wholesale sales of power in ERCOT. ERCOT is largely a bilateral wholesale power market, which allows buyers and sellers to competitively negotiate contracts for energy, capacity and ancillary services. ERCOT meets its system needs by using ancillary service capacity and running a balancing energy service. Balancing energy services procured by ERCOT generally comprise about 5% of the daily power market. ERCOT manages transmission congestion with zonal and intra-zonal type arrangements. The PUCT has approved a new nodal market design, which features locational marginal pricing for the ERCOT market. The new nodal market will allow ERCOT to perform centralized day-ahead unit commitment and economic dispatch processes based on bid prices. The nodal market design is scheduled for full implementation by mid-December 2008, but given this is a significant change in market design, a later implementation date is not inconceivable. Given the long-lead time to implement nodal pricing in ERCOT, which may include market rule changes not known at this time, we cannot predict the impact on our business.

 

The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own facilities in Texas have power generation company status at the PUCT and are either EWGs or QFs and are exempt from PUCT rate regulation. The PUCT recently adopted a wholesale market enforcement rule and rules regarding wholesale electric market power and resource adequacy in the ERCOT power region, including an increase in the offer cap for energy purchased by ERCOT to balance load and generation resources and maintain system frequency. The new resource adequacy rule establishes an energy-only model rather than the capacity-based resource adequacy model more common among RTOs or ISOs in the Eastern Interconnect. The current offer cap is scheduled to incrementally increase over the next several years. Under certain market conditions, the offer cap could be lowered below the current cap. Our subsidiaries are subject to the

recently adopted price caps, but only as it applies to sales of such energy services to ERCOT. At this time, we cannot accurately predict the impact of these new rules on the ERCOT market or on our business.

 

Northeast Region

 

New York and the Northeast regions are part of the NPCC NERC region, in which we have a total of seven natural-gas powered generating facilities (including one under construction in Ontario, Canada) with the capacity to generate a total of 1,392 MW. We have five generating plants in New York. NYISO manages the transmission system in New York and operates the state’s wholesale electricity markets. NYISO manages both day-ahead and real time energy markets using a zonal locational based marginal pricing mechanism that pays each generator the marginally accepted bid price for the energy it produces and delivers within a specified zone. NYISO currently has a bid cap for energy in New York which is expected to continue for the immediate future, and a different bid cap for installed capacity in New York City.

 

We have one plant in the Northeast region. ISO New England is the RTO for Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. ISO NE has broad authority over the day-to-day operation of the transmission system and operates a day-ahead and real time wholesale energy market.

 

Mid-Atlantic Region

 

Three of our facilities, with the capacity to generate a total of 253 MW (in which our net interest is 193.1 MW) sell into and purchase power from the markets operated by PJM, which is located in the RFC NERC region. We have access to the PJM transmission system pursuant to PJM’s Open Access Transmission Tariff. PJM operates the PJM Interchange Energy Market, which is the region’s spot market for wholesale electricity, provides ancillary services for its transmission customers, performs transmission planning for the region and dispatches generators accordingly. PJM administers day-ahead and real-time marginal cost clearing price markets and calculates electricity prices based on a locational marginal pricing model.

 

On August 31, 2005, PJM filed its RPM with FERC. This proposal is intended to replace its current capacity market rules. The new RPM proposal would provide for establishment of locational deliverability zones for capacity phased in over a several year period beginning on June 1, 2007. On December 22, 2006, FERC approved RPM. RPM is expected to increase opportunities for generators to receive more revenues for their capacity.

 

PJM and the MISO have been directed by FERC to establish a common and seamless market, an effort that is largely dependent upon the MISO’s ability first to establish and operate its markets. The development of a joint market is contingent on the approval of the internal costs to both entities to develop and operate the infrastructure necessary for joint operations. It is unclear at this time if either the respective entities or FERC will approve such costs to achieve a common and seamless market.

 

Midwest Region

 

We have four natural gas-fired plants with the capacity to generate a total of 1,933 MW operating within the MISO market, in which one is located in the RFC and three are located in the MRO NERC regions. MISO is a FERC approved RTO that provides independent administration of the electric power grid. MISO is a competitive wholesale market that features a nodal market with real-time and day-ahead markets as well as a Firm Transmission Rights market. MISO, by default, has an energy-only based resource adequacy model, but it is considering a capacity-based resource adequacy model similar to those found in northeastern markets.

 

We have three natural gas-fired plants with the capacity to generate a total of 1,814 MW operating in the SPP footprint. SPP is an RTO approved by FERC that provides independent administration of the electric power grid. SPP is a competitive wholesale market that features a nodal market with a real-time market, but it does not have a capacity market. An energy imbalance service market began on February 1, 2007.

 

Southeast Region

 

We have 12 natural gas-fired plants with the capacity to generate a total of 6,332 MW (in which our net interest is 5,726 MW) operating in the SERC and the FRCC NERC regions. Opportunities to negotiate bilateral, individual

contracts and long-term transactions with investor owned utilities, municipalities and cooperatives exist within these footprints. In addition to entering into bilateral transactions, there is a limited opportunity to capture option value in the short-term market. In the Entergy sub-region, SPP has been designated as the ICT, which is under development. In this capacity, the ICT provides oversight of the Entergy transmission system. Also under development is a WPP, which will result in a formal process by which Entergy will procure competitive wholesale power. At this time, we cannot accurately predict the impact of the ICT or the WPP on our business.

 

Federal Regulation of Transportation and Sale of Natural Gas

 

Because the majority of our electric generating capacity is derived from natural gas-burning facilities, we are broadly impacted by federal regulation of natural gas transportation. Furthermore, our two natural gas transportation pipelines in Texas are subject to FERC regulation. Under the NGA, the NGPA and the Outer Continental Shelf Lands Act, FERC is authorized to regulate pipeline, storage and liquefied natural gas facility construction; the transportation of natural gas in interstate commerce; the abandonment of facilities; and the rates for services.

 

The cost of natural gas is ordinarily the largest operational expense of a gas-fired project and is critical to the project’s economics. The risks associated with using natural gas can include the need to arrange gathering, processing, extraction, blending and storage, as well as transportation of the gas from great distances, including obtaining removal, export and import authority if the gas is imported from a foreign country; the possibility of interruption of the gas supply or transportation (depending on the quality of the gas reserves purchased or dedicated to the project, the financial and operating strength of the gas supplier, whether firm or non-firm transportation is purchased and the operations of the gas pipeline); regulatory diversion; and obligations to take a minimum quantity of gas and pay for it (i.e., take-and-pay obligations). The use of pipelines for delivery of natural gas has proven to be an efficient and reliable method of meeting customers’ fuel needs with a low risk of supply interruption.

 

State Energy Regulation

 

State PUCs have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA. Since a PPA becomes a part of a utility’s cost structure (generally reflected in its retail rates), PPAs with independent electricity producers, such as EWGs, are potentially under the regulatory purview of PUCs and in particular the process by which the utility has entered into the PPAs. A PUC is generally inclined to authorize the purchasing utility to pass through to the utility’s retail customers the expenses associated with a PPA with an independent power producer, although there may be circumstances when it would disallow full cost recovery. Because all of our affiliates are either QFs or EWGs, none of our affiliates are currently subject to direct rate regulation by a state PUC. However, states may also assert jurisdiction over the siting and construction of electricity generating facilities including QFs and EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. In California, for example, the PUC was required by statute to adopt and enforce maintenance and operation standards for generating facilities “located in the state,” including EWGs but excluding QFs, for the purpose of ensuring their reliable operation. As the owner and operator of generating facilities in California, our subsidiaries are subject to the generation facilities maintenance and operation standards and the general duty standards that are enforced by the CPUC.

 

State PUCs also have jurisdiction over the transportation of natural gas by LDCs as well as their rates. Each state’s regulatory laws are somewhat different; however, all generally require the LDC to obtain approval from the PUC for the construction of facilities and transportation services if the LDC’s generally applicable tariffs do not cover the proposed transaction. In addition, PUC regulations can establish the priority of curtailment of gas deliveries when gas supply is scarce. We own and operate certain pipeline assets in certain states where we have plants. LNG deliveries into the LDC pipeline system could impact plant operations and the ability to meet emission limits unless appropriate gas specifications are implemented.

 

In addition, our Texas pipelines are subject to regulation as gas utilities by the Railroad Commission of Texas for rates and services.

 

Environmental Regulations

 

Our facilities and equipment necessary to support them are subject to extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, hazardous materials handling and disposal, waste disposal and noise regulations. Noncompliance with environmental laws and regulations can result in the imposition of civil or criminal fines or penalties. In some instances, environmental laws also may impose clean-up or other remedial obligations in the event of a release of pollutants or contaminants into the environment. The following federal laws are among the more significant environmental laws that apply to us. In most cases, analogous state laws also exist that may impose similar and, in some cases, more stringent requirements on us than those discussed below. Our general position with respect to these laws attempts to take advantage of our relatively clean portfolio of power plants as compared to our larger competitors.

 

Climate Change Legislation

 

Our emissions of CO₂ amounted to over 35 million tons in 2005. Although there are no laws regulating GHG emissions, there has been increased attention to climate change in the U.S. Several bills to regulate GHG from the electricity section were introduced in the U.S. House of Representatives and the Senate in 2006, and more are expected in 2007, making climate change initiatives an emerging priority on the environmental legislative and regulatory front. Therefore, regulation of GHGs could have a material impact on the conduct of our business. We are actively participating in the debates surrounding federal regulation of GHG emissions from the electric generating sector in an attempt to minimize future impacts to our business.

 

Supreme Court Case Regarding Regulation of GHG

 

Twelve states and various environmental groups filed suit against the EPA in Commonwealth of Massachusetts v. EPA seeking confirmation that the EPA has an existing obligation to regulate GHGs, under the CAA. The EPA refused to regulate GHG emissions from motor vehicles on the basis that the CAA did not require regulation of GHGs, including carbon dioxide, as pollutants. In July 2005, the U.S. Court of Appeals for the District of Columbia Circuit supported the EPA’s position.

 

After a series of appeals, the U.S. Supreme Court agreed in March 2006 to consider the case. We submitted a brief of amicus curiae in support of the plaintiffs’ case, and oral arguments were made before the U.S. Supreme Court in November 2006. Although the U.S. Supreme Court has not yet rendered a decision on the matter, the outcome of this (and similar) suits could affect the overall regulation of GHGs under the CAA.

 

Climate Change — Regional Activities

 

Although standards have not been developed at the national level, several states and regional organizations are developing, or already have developed, state-specific or regional legislative initiatives to reduce GHG emissions through mandatory programs. The two most advanced programs relate to climate change regulation in California and actions taken by a coalition of northeast states. The evolution of these programs could have a material impact on our business. However, we believe we will face a lower compliance burden than some competitors due to the relatively low GHG emission rates of our fleet.

 

In California, AB 32 and SB 1368 were signed into law in September 2006. AB 32 creates a statewide cap on GHG emissions and requires that the state return to 1990 emission levels by 2020; implementation is slated to begin by January 1, 2010. SB 1368 requires GHG emissions performance standard for long-term procurement of electricity, which would apply to all load-serving entities in the state by mid-2007.

 

Beginning in 2009, nine northeast and mid-Atlantic states will launch RGGI which will affect our facilities in Maine, New York and New Jersey. RGGI will cap CO₂ emissions at current levels, through 2015, and the cap will decrease annually by 2.5% until 2019, when the total RGGI cap will be reduced by 10% compared to the initial cap level. Each participating state will receive a share of the total RGGI cap, and decisions on how the allowances will be distributed will be made by each state. However, RGGI requires that at least 25% of the state allocations be set

aside for public purposes, which are expected to be distributed through auctions instead of direct allocations to affected generators.

 

State-level implementation of RGGI is in process, but some states — including New York — have expressed interest in pursuing an auction process to distribute all allowances, which would require fossil fuel-fired generating units to purchase allowances on the open market.

 

Clean Air Act

 

The Clean Air Act provides for the regulation of air quality and air emissions, largely through state implementation of federal requirements. In 1990, Congress amended CAA to specifically provide for acid deposition control through the regulation of NOx and SO₂ emissions from electric generating units. We believe that all of our operating plants and relevant oil and gas-related facilities are in compliance with federal performance standards mandated under CAA as amended.

 

Acid Rain Program

 

As a result of the 1990 CAA amendments, the EPA established a cap and trade program for SO₂ emissions from electric generating units throughout the U.S. Under this program, a permanent ceiling (or cap) was set of 8.95 million allowances for total annual SO₂ allowance allocations to power generators. Each allowance permits a unit to emit one ton of SO₂ during or after a specified year, and allowances may be bought, sold or banked. All but a small percentage of allowances were allocated to electric generating units placed into service before 1990. None of our facilities received an allocation, so we must purchase allowances to cover all SO₂ emissions from our affected facilities and satisfy our compliance obligations. Since our entire fleet emits about 200 tons of SO₂ per year, we believe that our compliance expense for this program will be relatively insignificant compared to many of our competitors.

 

NOx SIP Call

 

In response to concerns about interstate contributions to ozone concentrations above the NAAQS, the EPA promulgated regulations establishing a cap and trade program for NOx emissions from electric generating and industrial steam generating units in most of the eastern U.S. in May 2004. Under these regulations, the EPA set a NOx emissions cap for each state and each affected unit receives NOx emissions allowances through allocation mechanisms that vary by state. Emission compliance obligations apply during the ozone season, which extends from May through September. If an affected unit exceeds its allocated allowances, it must purchase additional allowances to resolve the shortfall.

 

We own and operate numerous facilities that are affected by this program. To date, NOx allowance allocations have been sufficient to cover all emissions and we have sold some surplus allowances for a small profit. We believe that the relatively low NOx emission rate of our fleet in general keeps our compliance costs for this program lower than those of many of our competitors.

 

Clean Air Interstate Rule

 

CAIR is intended to reduce SO₂ and NOx emissions in 29 eastern states and the District of Columbia and address transport of pollutants that contribute to nonattainment of NAAQS for fine particulate matter and ozone. The rule includes both seasonal and annual NOx control programs as well as an annual SO₂ control program. A significant portion of our generating fleet will be subject to these programs.

 

The compliance deadline for Phase I of the NOx control program becomes effective in 2009 and the SO₂ control program becomes effective in 2010, with the final compliance phase for both beginning in 2015. With respect to SO₂ emissions, CAIR relies largely upon the cap and trade mechanism established under the EPA’s acid rain program discussed above and compliance with CAIR will be demonstrated through the use of SO₂ allowances issued under the EPA’s acid rain program. CAIR will require the use of two emission allowances for each ton of SO₂ emitted beginning in 2010, and 2.87 emission allowances for each ton of SO₂ emitted beginning in 2015. As our

fleet’s SO₂ emissions are low, we expect our costs of compliance with CAIR to be lower than those of many of our competitors.

 

CAIR provides for a new NOx cap and trade mechanism that issues allowances to the majority of affected sources. NOx emissions will be covered with a one-for-one ratio of allowances to tons; however, the total emissions cap will be reduced in 2015, which generally will have the effect of reducing allowance allocations to affected sources.

 

In August 2005, the EPA published a proposed rule that includes a FIP to implement the provisions of CAIR. Each CAIR-affected state has the option of adopting the FIP or developing their own state-level plan, which allows individual consideration of NOx allocation mechanisms, among other considerations. In general, the FIP allocation mechanism is less favorable to us than the various proposed state-level rulemakings, and we have actively participated in various state-level rulemakings to achieve more favorable allocation treatment for our facilities. We do not believe that CAIR will require significant compliance expenditures.

 

Houston/Galveston Nonattainment

 

Regulations adopted by the TCEQ to attain the one-hour NAAQS for ozone included the establishment of a cap and trade program for NOx emitted by power generating facilities in the Houston/Galveston ozone nonattainment area. We own and operate seven facilities that participate in this program, all of which have, or will receive, NOx allowance allocations based on historical operating profiles.

 

At this time, our Houston-area generating facilities have sufficient NOx allowances to meet forecasted obligations under the program. However, TCEQ may modify future allocations of NOx to facilities participating in the trading program in support of efforts to comply with the new 8-hour ozone NAAQS.

 

Should allowance shortfalls occur, we would be required to purchase NOx allowances or install emissions control equipment on certain facilities.

 

Multipollutant Legislation

 

There also have been numerous federal legislative proposals made in the past several years to further reduce emissions of SO₂, NOx and mercury, as well as to regulate emissions of CO₂ for the first time. Because our gas-fired and geothermal power plants has a lower emissions rate than the average U.S. coal- or oil-fired power plant as discussed in Item 1. “Business — Environmental Stewardship,” it is possible that we will be less impacted by such regulation than owners of older, higher emitting fleets. However, the full scope of impact will depend on the details of implementation associated with specific legislation, such as allocation of emissions allowances and point of regulation.

 

Clean Water Act

 

The federal Clean Water Act establishes rules regulating the discharge of pollutants into waters of the U.S. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, from certain of our facilities. We believe that, with respect to our geothermal operations, we are exempt from newly promulgated federal storm water requirements. We are required to maintain a spill prevention control and countermeasure plan with respect to certain of our oil and gas facilities. We believe that we are in material compliance with applicable discharge requirements of the federal Clean Water Act.

 

Safe Drinking Water Act

 

Part C of the Safe Drinking Water Act mandates established the underground injection control program that regulates the disposal of wastes by means of deep well injection, which is used for geothermal production activities. With the passage of EPAct 2005, oil, gas and geothermal production activities are exempt from the underground injection control program under the Safe Drinking Water Act.

 

Resource Conservation and Recovery Act

 

RCRA regulates the management of solid and hazardous waste. With respect to our solid waste disposal practices at the power generation facilities and steam fields located in the Geysers region of northern California, we are also subject to certain solid waste requirements under applicable California laws. We believe that our operations are in material compliance with RCRA and all such laws.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

CERCLA, also referred to as Superfund, requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorizes the EPA to take any necessary response action at Superfund sites, including ordering potentially responsible parties liable for the release to pay for such actions. Potentially responsible parties are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of wastes sent to, a site. As of the present time, we are not subject to any material liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send certain of our wastes to third party waste disposal sites. As a result, there can be no assurance that we will not incur liability under CERCLA in the future.

 

Canadian Environmental, Health and Safety Regulations

 

Our Canadian power projects are also subject to extensive federal, provincial and local laws and regulations adopted for the protection of the environment and to regulate land use. We believe that we are in material compliance with all applicable requirements under Canadian law.

 

Regulation of Canadian Gas

 

The Canadian natural gas industry is subject to extensive regulation by federal and provincial authorities. At the federal level, a party exporting gas from Canada must obtain an export license from the National Energy Board. The National Energy Board also regulates Canadian pipeline transportation rates and the construction of pipeline facilities. Gas producers also must obtain a removal permit or license from each provincial authority before natural gas may be removed from the province, and provincial authorities regulate intra-provincial pipeline and gathering systems. In addition, a party importing natural gas into the U.S. or exporting natural gas from the U.S. first must obtain an import or export authorization from the U.S. Department of Energy.

 

EMPLOYEES

 

As of December 31, 2006, we employed 2,306 full-time people, of whom 48 were represented by collective bargaining agreements. We have never experienced a work stoppage or strike. As part of our restructuring program, in 2006 we began implementing staff reductions, and approximately 850 positions have been eliminated out of a total of approximately 1,100 positions (over one-third of our workforce of 3,265 full-time people as of December 31, 2005) originally slated for elimination. We continue to evaluate our staffing needs and expect that there will be further staff reductions in 2007, but the total number may change depending on whether certain asset sales or other divestitures or facility shutdowns occur.

 

Risks Relating to Bankruptcy

 

We are subject to the risks and uncertainties associated with our Chapter 11 and CCAA proceedings.  We continue to operate our business as debtors-in-possession under the jurisdiction of the Bankruptcy Courts and in accordance with the applicable provisions of the Bankruptcy Code, the CCAA and orders of the Bankruptcy Courts. As a result, we are subject to the risks and uncertainties associated with our Chapter 11 cases and CCAA proceedings which include, among other things:

 

 

 

These risks and uncertainties could negatively affect our business and operations in various ways. For example, events or publicity associated with our Chapter 11 and CCAA proceedings could adversely affect our relationships with customers, vendors and employees, which in turn could adversely affect our operations and financial condition, particularly if such proceedings are protracted.

 

As a result of our bankruptcy filings and the other matters described herein, including the uncertainties related to the fact that we have not yet had time to complete and obtain confirmation of a plan of reorganization, there is substantial doubt about our ability to continue as a going concern. Our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to maintain adequate cash on hand; (ii) our ability to generate cash from operations; (iii) the cost, duration and outcome of the restructuring process; (iv) our ability to comply with the terms of our existing DIP Facility and Replacement DIP Facility and the adequate assurance provisions of the Cash Collateral Order and (v) our ability to achieve profitability following a restructuring. These challenges are in addition to those operational and competitive challenges that we face in connection with our business.

 

Accordingly, trading in our securities during the pendency of our Chapter 11 and CCAA proceedings is highly speculative and poses substantial risks. These risks include extremely volatile trading prices. In addition, during the pendency of the Chapter 11 proceeding, the U.S. Bankruptcy Court has entered an order that places certain limitations on trading in our common stock and certain securities, including options, convertible into our common stock, and has also provided the potentially retroactive application of notice and sell-down procedures for trading in claims against the U.S. Debtors’ estates (in the event that such procedures are approved in the future). Holders of our securities, especially holders of our common stock, may not be able to resell such securities and, in connection with our reorganization, may have their securities cancelled and in return receive no payment or other consideration, or a payment or other consideration that is less than the par value or the purchase price of such securities.

 

We may not be able to confirm or consummate a plan of reorganization.  In order to successfully emerge from our Chapter 11 cases as a viable company, we must develop, obtain requisite U.S. Bankruptcy Court and creditor approval of, and consummate a Chapter 11 plan of reorganization. This process requires us to meet certain statutory requirements with respect to adequacy of disclosure regarding a plan of reorganization, soliciting and obtaining creditor acceptances of a plan, and fulfilling other statutory conditions for confirmation. We may not receive the requisite acceptances to confirm a plan of reorganization. Even if the requisite acceptances to a plan of reorganization are received, the U.S. Bankruptcy Court may not confirm the plan. In addition, even if a plan of reorganization is confirmed, we may not be able to consummate such plan.

 

Our ability to confirm and consummate a plan of reorganization will depend primarily upon the operational performance of our power generation facilities, movements in power and natural gas prices over time, our marketing and risk management activities, and our ability to successfully implement our business plan.

 

If a plan of reorganization is not confirmed by the U.S. Bankruptcy Court, or if we are unable to successfully consummate a plan after confirmation, it is unclear whether we would be able to reorganize our businesses and what, if any, distributions holders of claims against us ultimately would receive with respect to their claims. If an alternative reorganization could not be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as an economically viable, reorganized entity.

 

On December 6, 2006, the U.S. Bankruptcy Court granted our application for an extension of the period during which we have the exclusive right to file a reorganization plan or plans from December 31, 2006 to June 20, 2007, and granted us the exclusive right until August 20, 2007, to solicit acceptance thereof. The U.S. Bankruptcy Court has the power to terminate these periods prior to June 20, 2007, and August 20, 2007, respectively, and we can make no assurance that the U.S. Bankruptcy Court will not do so. As the Bankruptcy Code currently provides for a maximum exclusivity period of 18 months and 20 months, respectively, to file and solicit acceptance of a plan or plans of reorganization, there can be no assurance that the U.S. Bankruptcy Court would grant any further extension of those periods.

 

Our filings under Chapter 11 and the CCAA have exposed certain of our Non-Debtor subsidiaries to the potential exercise of rights and remedies by debt or equity holders.  Our filings under Chapter 11 and the CCAA and constraints on our business during the proceedings have resulted in (and could result in additional) defaults under certain project loan agreements of Non-Debtor subsidiaries. These filings and limitations on the ability of certain of the Calpine Debtor subsidiaries to make payments under intercompany agreements with Non-Debtor subsidiaries have resulted in defaults or potential defaults under debt or preferred equity interests issued by or certain lease obligations of certain of those Non-Debtor subsidiaries. Absent cure, waiver or other resolution in respect of these defaults from the applicable creditors or equity holders, we may not be able to prevent the acceleration of the subsidiary debt or lease obligations and the exercise of other remedies against the subsidiaries, including a sale of the equity or assets of such subsidiaries, a termination of the leasehold rights or the enforcement of buy-out rights or other remedies. While we have been able to obtain waivers with respect to certain defaults, we may not be able to extend such waivers and forbearances. If we are unable to obtain waivers or extend current waivers or make other arrangements with respect to current or future defaults, if any, under debt, preferred equity or leases of Non-Debtor subsidiaries, such Non-Debtor subsidiaries may be adversely affected, or the holders of debt or equity of such Non-Debtor subsidiaries may take actions or exercise remedies, including sales of the assets of such Non-Debtor subsidiaries, which may cause adverse effects to our financial condition or results of operations as a whole.

 

Transfers of our equity, or issuances of equity in connection with our restructuring, may impair our ability to utilize our federal income tax net operating loss carryforwards in the future.  Under federal income tax law, a corporation is generally permitted to deduct from taxable income in any year net operating losses carried forward from prior years. We have NOL carryforwards of approximately $3.8 billion as of December 31, 2006. Our ability to deduct NOL carryforwards could be subject to a significant limitation if we were to undergo an “ownership change” for purposes of Section 382 of the Internal Revenue Code of 1986, as amended, during or as a result of our Chapter 11 cases. During the pendency of the Chapter 11 proceeding, the U.S. Bankruptcy Court has entered an order that places certain limitations on trading in our common stock or certain securities, including options, convertible into our common stock. The U.S. Bankruptcy Court has also provided the potentially retroactive application of notice and sell-down procedures for trading in claims against the U.S. Debtors’ estates (in the event that such procedures are approved in the future). However these limitations may not prevent an “ownership change” and our ability to utilize our net loss carryforwards may be significantly limited as a result of our reorganization.

 

Bankruptcy laws may limit our secured creditors’ ability to realize value from their collateral.  Upon the commencement of a case for relief under Chapter 11 of the Bankruptcy Code, a secured creditor is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from such debtor, without bankruptcy court approval. Moreover, the Bankruptcy Code generally permits the debtor to continue to retain and use collateral even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security if and at such times as the

bankruptcy court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the Chapter 11 case. A bankruptcy court may determine that a secured creditor may not require compensation for a diminution in the value of its collateral if the value of the collateral exceeds the debt it secures.

 

In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary power of a bankruptcy court, it is impossible to predict:

 

 

In addition, the instruments governing certain of our indebtedness provide that the secured creditors (or their applicable agents) may not object to a number of important matters following the filing of a bankruptcy petition. Accordingly, it is possible that the value of the collateral securing our indebtedness could materially deteriorate and secured creditors would be unable to raise an objection.

 

Furthermore, if the U.S. Bankruptcy Court determines that the value of the collateral is not sufficient to repay all amounts due on applicable secured indebtedness, the holders of such indebtedness would hold a secured claim only to the extent of the value of their collateral and would otherwise hold unsecured claims with respect to any shortfall. The Bankruptcy Code generally permits the payment and accrual of post-petition interest, costs and attorney’s fees to a secured creditor during a debtor’s Chapter 11 case only to the extent the value of its collateral is determined by a bankruptcy court to exceed the aggregate outstanding principal amount of the obligations secured by the collateral.

 

Some or all of the U.S. Debtors could be substantively consolidated.  There is a risk that an interested party in the Chapter 11 cases, including any of the U.S. Debtors, could request that the assets and liabilities of Calpine Corporation, or those of one or more of our U.S. Debtor subsidiaries, be substantively consolidated with those of one or more other U.S. Debtors. While it has not been requested to date, we cannot assure you that substantive consolidation will not be requested in the future, or that the U.S. Bankruptcy Court would not order it. If litigation over substantive consolidation occurs, or if substantive consolidation is ordered, the ability of a U.S. Debtor that has been substantively consolidated with another U.S. Debtor to make payments required with respect to its unsecured debt, or its secured debt to the extent that the claims of holders of such secured debt are disallowed or such debt is under secured, could be adversely affected. For example, the rights of unsecured debt holders of Calpine Corporation may be diminished or diluted if Calpine Corporation were consolidated with one or more entities that have a higher amount of unsecured priority claims or other unsecured claims relative to the value of their assets available to pay such claims (after payment of or provision for allowed secured claims). In addition, the rights of shareholders of Calpine Corporation may be diminished or diluted if Calpine Corporation or other U.S. Debtors were consolidated with entities that are insolvent.

 

Our financial results may be volatile and may not reflect historical trends.  While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections, and claims assessments may significantly impact our Consolidated Financial Statements. As a result, our historical financial performance is likely not indicative of our financial performance post-bankruptcy. In addition, upon emergence from Chapter 11, the amounts reported in our subsequent Consolidated Financial Statements may materially change relative to our historical Consolidated Financial Statements, including as a result of revisions to our operating plans pursuant to our plan of reorganization. In addition, as part of our emergence from bankruptcy protection, we expect that we will be required to adopt fresh start accounting. If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date. The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our Consolidated Balance Sheets. In addition, our financial results after the application of fresh