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As filed with the Securities and Exchange Commission on May 8, 2008

Registration No. 333-          



SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

NOBLE ENVIRONMENTAL POWER, LLC*
(Exact name of registrant as specified in its charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  4911
(Primary Standard Industrial Classification Code Number)
  73-1717075
(IRS Employer
Identification No.)

8 Railroad Avenue, Suite 8, Second Floor
Essex, CT 06426
(860) 581-5010
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

C. Kay Mann
Senior Vice President, General Counsel and Secretary
Noble Environmental Power, LLC
8 Railroad Avenue, Suite 8, Second Floor
Essex, CT 06426
(860) 581-5010
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Rachel W. Sheridan, Esq.
Patrick H. Shannon, Esq.
Latham & Watkins LLP
555 Eleventh Street NW, Suite 1000
Washington, DC 20004
(202) 637-2200
  Andrew R. Keller, Esq.
Simpson Thacher & Bartlett LLP
425 Lexington Avenue
New York, NY 10017
(212) 455-2000

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

         If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box. o

         If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o


         If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o


         If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o


CALCULATION OF REGISTRATION FEE


Title of each Class of
Securities to be Registered

  Proposed Maximum Aggregate Offering Price(a)(b)
  Amount of Registration Fee

Common stock, $0.01 par value   $375,000,000   $14,737.50

(a)
Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(o) promulgated under the Securities Act of 1933.

(b)
Including shares of common stock that the underwriters have the option to purchase.

*
The registrant's board of managers has approved the conversion of the registrant into a corporation to be named Noble Environmental Power, Inc. The conversion will become effective following the effectiveness of this registration statement.

         The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.




Subject to Completion, dated            , 2008

PROSPECTUS

The information contained in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

         Shares

GRAPHIC

Noble Environmental Power, Inc.

Common Stock


We are offering                shares of our common stock in this initial public offering. No public market currently exists for our common stock.

We intend to apply to have our common stock listed on The NASDAQ Global Market under the symbol "NEPI." We anticipate that the initial public offering price will be between $                and $                per share.

Investing in our common stock involves risks. See "Risk Factors"
beginning on page 13.

 
  Per
share

  Total
Initial public offering price   $     $  
Underwriting discounts and commissions   $     $  
Proceeds to Noble (before expenses)   $     $  

We have granted the underwriters a 30-day option to purchase up to an additional                shares from us on the same terms and conditions as set forth above to the extent the underwriters sell more than                shares of common stock in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares to purchasers on or about                        , 2008.


LEHMAN BROTHERS   JPMORGAN   CREDIT SUISSE

                      , 2008



ARTWORK TO BE FILED BY AMENDMENT



TABLE OF CONTENTS

 
  Page
Prospectus Summary   1
Risk Factors   13
Special Note Regarding Forward-Looking Statements   33
Use of Proceeds   35
Dividend Policy   36
Capitalization   37
Dilution   39
Selected Consolidated Financial Data   41
Management's Discussion and Analysis of Financial Condition and Results of Operations   43
Description of Certain Financing Arrangements   61
Industry Overview   71
Business   82
Management   106
Certain Relationships and Related Party Transactions   125
Principal Stockholders   130
Description of Capital Stock   132
Shares Eligible for Future Sale   135
Certain United States Federal Income Tax Considerations to Non-United States Holders   137
Underwriting   141
Legal Matters   146
Experts   146
Where You Can Find More Information   146
Glossary of Selected Industry Terms   147
Index to Financial Statements   F-1

        You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with information different from that contained in this prospectus. We are offering to sell, and seeking offers to buy, shares of common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of the shares of common stock.

        Until and including                        , 2008, 25 days after the commencement of this offering, all dealers that buy, sell or trade shares of our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.



PROSPECTUS SUMMARY

        This summary highlights selected information contained elsewhere in this prospectus and does not contain all of the information you should consider in making your investment decision. You should read the following summary together with all of the more detailed information regarding us and our common stock being sold in the offering, including our financial statements and the related notes, the information set forth under the headings "Risk Factors" and "Management's Discussion and Analysis of Financial Conditions and Results of Operations" appearing elsewhere in this prospectus. Unless we state otherwise, "Noble Environmental Power," "Noble," the "Company," "we," "us" and "our" refer to: (i) Noble Environmental Power, LLC, and its subsidiaries, taken as a whole; and (ii) Noble Environmental Power, Inc. as of the completion of our corporate reorganization and thereafter. Unless we state otherwise, all information in this prospectus gives effect to our corporate reorganization discussed in "Corporate Reorganization" below.

Our Company

        We are a rapidly growing wind energy company operating 282 megawatts, or MW, of electrical generating capacity with more than 950 MW of additional capacity that we expect to commence operations during 2008 and 2009. We are focused on developing, financing, constructing, owning and operating windparks in attractive energy markets in the United States. Our strategy is to grow our business principally through organic development in regions with deregulated power markets, acceptable wind resources and favorable legislative and economic incentives such as renewable portfolio standard, or RPS, programs and active renewable energy certificate, or REC, markets. Through RPS programs and REC markets, we are able to monetize the environmental attributes associated with our power, in addition to generating revenue from the actual power we produce. Operating in these attractive deregulated energy markets also enables us to execute our energy hedging strategy, which helps stabilize our revenues while allowing us to benefit from future increases in energy prices.

        We were founded in August 2004 and commenced operations of our first windparks in March 2008. We have grown into a fully integrated wind energy company with 152 employees, with the capability to develop, finance, construct, own and operate our windparks. We will utilize our understanding of the commodity markets to site our windparks in attractive regions and to monetize the output of our projects effectively.

        In addition to our current capacity of 282 MW, we have begun construction of additional windparks in New York and Texas that we expect will provide an additional 465 MW of capacity in 2008. We plan to grow our capacity significantly over the next several years. By the end of 2012, we expect to have approximately 3,850 MW of capacity as we further expand into attractive wind energy markets in Maine, Michigan, Minnesota, New Hampshire, Vermont and Wyoming. In addition, we continuously identify and evaluate new windparks as part of our core business strategy. Windpark project development has been and will continue to be one of our core strengths and areas of focus. Based on our historical success in identifying new windpark projects, we expect that these project development efforts will result in an additional 4,000 MW development pipeline of windparks, which could be constructed after 2012.

        We also maintain strong relationships with major turbine suppliers, who we expect will provide the turbines required for our expanding windpark portfolio. We have secured access to the turbines needed for our projects slated for construction through 2009. We believe that the strong track record of our experienced management team, the expertise of our project development team dedicated to sourcing new opportunities, our integrated business model and our turbine supply relationships provide us with the knowledge and resources necessary to rapidly grow our windpark portfolio.

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Growth in Our Windpark Portfolio

         LOGO

(1)
Capacity represents the maximum output, measured in megawatts, that an individual wind turbine generator is designed to produce. The capacity of a windpark equals the capacity of the generators multiplied by the number of generators included in the windparks.

Our Windpark Portfolio

        Our operational project portfolio is located in New York and consists of three windparks: Bliss, Clinton and Ellenburg. We refer to these windparks as our Initial New York Windparks. Additionally, we have 465 MW of projects currently in construction in New York at our Altona, Bellmont, Chateaugay and Wethersfield windparks and in Texas at Phase I of our Great Plains windpark, all of which we expect to commence operations in the fourth quarter of 2008. We also have 1,205 MW of projects currently in development, which we expect to commence operations in 2009 and 2010, and an additional 1,900 MW of projects in development, which we expect to commence operations during 2011 and 2012. Substantially all of these identified projects are located in attractive deregulated energy markets and in areas that we have determined have acceptable wind resources. For projects that we expect will commence operations between 2008 and 2010, we have secured control of the land necessary to construct our windparks, identified transmission interconnection and established relationships in the local communities. In addition, we have secured all of the turbines needed to support our projects slated for construction through 2009.

        For the majority of our 2011 and 2012 projects, we have secured a portion of the land necessary to place our turbines and have analyzed the characteristics of the applicable energy, capacity and REC markets. We have also performed preliminary wind analysis, identified transmission interconnection and initiated our public outreach process within the local communities.

        We continue to grow our windpark development pipeline and identify new potential projects every year through our integrated regional land, interconnection, market and meteorological development process. We identify new potential projects utilizing a cross-functional team consisting of development, commodities and engineering specialists to expedite our research process. This strategy allows us to quickly examine new areas for development, determine a potential project's viability and pursue windparks in attractive markets. Over the next five years, we estimate that our development team will identify approximately 4,000 MW of additional windpark development projects, which could be constructed after 2012.

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        A summary description of our portfolio follows in the chart below.


Our Windpark Portfolio

Projects

  State
  Capacity(1)
(MW)

Initial New York Windparks        
Bliss   NY   100.5
Clinton   NY   100.5
Ellenburg   NY   81.0
       
Capacity Subtotal       282.0
       

2008 Windparks

 

 

 

 
Altona   NY   97.5
Bellmont   NY   21.0
Chateaugay   NY   106.5
Wethersfield   NY   126.0
Great Plains I   TX   114.0
       
Expected Capacity Subtotal       465.0
       

2009 Windparks

 

 

 

 
Ball Hill / Villanova   NY   100.5
Centerville / Rushford   NY   100.5
Chateaugay II   NY   19.5
Great Plains II   TX   126.0
Mitchell County I (Phase I)   TX   153.0
       
Expected Capacity Subtotal       499.5
       
2010 Windparks        
Burke   NY   60.0
Farmersville   NY   100.5
Mitchell County I (Phase II)   TX   147.0
Mitchell County II / Pecos County   TX   150.0
Grandpa's Knob   VT   72.0
Granite Reliable(2)   NH   75.0
Flat Hill I   MN   100.5
       
Expected Capacity Subtotal       705.0
       

Total Expected Capacity Through 2010

 

 

 

1,951.5
       

2011 / 2012 Windparks

 

 

 

 
Expansions of existing windparks       800.0
New windparks in existing states       550.0
Windparks in new states       550.0
       
Estimated Capacity Subtotal       1,900.0
       

Total Expected Capacity through 2012

 

 

 

3,851.5
       

(1)
These megawatt numbers represent the megawatts we expect to have in operation during these periods. These numbers may vary based on a variety of factors discussed elsewhere in this prospectus. See "Risk Factors" beginning on page 13 of this prospectus.

(2)
This megawatt number represents the net megawatts allocated to us after deducting the anticipated 25% interest of our potential partner in the development of this project. The size of the windpark to be developed at Granite Reliable is expected to be 99 MW.

3


Market Opportunity

        From its beginnings in California, wind energy in the U.S. has expanded steadily to 35 of the 50 states. Additionally, the total capacity of U.S. windparks increased by a factor of more than six from 2,500 MW to over 16,800 MW between December 1999 and December 2007. Despite this growth, wind energy generation still only represented just under 1% of U.S. electricity supply in 2006, and we believe that the prospects for further growth are very favorable. According to Emerging Energy Research, wind energy could provide approximately 50,000 MW of capacity in the U.S. by 2015. We believe that the key drivers for this growth trend are as follows:

    Increases in electricity demand coupled with the rising cost of fossil fuels used for conventional energy generation;

    Heightened environmental concerns, including legislative and popular support to reduce carbon dioxide, or CO2, emissions and other greenhouse gases;

    Regulatory mandates, such as state RPS programs, as well as federal tax incentives including production tax credits, or PTCs, and accelerated tax depreciation that benefit wind energy generators;

    Improvements in wind energy technology;

    Increasing obstacles to the construction of conventional fuel plants; and

    Abundant wind resources in attractive energy markets within the U.S.

Our Competitive Strengths

        We believe that the following strengths position us to profitably grow our windpark portfolio in the rapidly developing U.S. wind energy market:

High-quality portfolio of operating, in-construction and in-development windparks located in attractive U.S. energy markets

        We believe that our strategically located portfolio of operating, in-construction and in-development windparks ideally positions us within the rapidly growing U.S. wind energy market. Furthermore, we expect that our development portfolio will give us significant scale across a geographically diverse national footprint. We carefully select our project sites to ensure that they are in regions characterized by acceptable wind resources, high power prices in deregulated energy markets and favorable renewable energy policies. We believe our management's experience in developing windparks in new markets and adding projects in our existing markets will enable us to continue to successfully expand our development portfolio. Additionally, we believe our management's understanding of deregulated energy markets enables us to maximize the value of our development portfolio.

Fully integrated in-house capabilities to develop, finance, construct, own and operate windparks and to support the continuing growth of our portfolio

        Our fully integrated, cross-functional organizational structure enables us to develop, finance, construct, own and operate each of our projects with a long-term ownership perspective. Our commodities and risk management team works closely with our developers and meteorological team on identifying regions for optimal project development. Collaboration among the developers, engineers and managers on each of our projects allows us to transition from one stage to the next and to regularly identify process and technical improvements over the life-cycle of each project. We have a dedicated development team of 33 professionals engaged in activities including site selection, market analysis, land acquisition, community relations and permitting. We also have significant engineering and construction, or E&C, and operations and maintenance, or O&M, expertise, through our combined

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teams of 68 employees. Finally, our management team has extensive project finance and commodity hedging expertise, allowing us to optimize our capital structure and reduce the impact of spot market energy price volatility. This integrated project management strategy will enable us to continuously improve the development timing, cost and capital structure and revenue optimization of projects across our portfolio.

Experienced and proven management team with an average of more than 20 years of experience with complex power projects

        Our management team has extensive knowledge of every aspect of the development, financing, construction and operation of windparks, as well as many years of experience in traditional independent electricity generation. Our senior management has an average of over 20 years of experience and involvement in bringing domestic and international power projects online, from initial development through financing to ongoing operations and maintenance.

Strong relationships with major turbine suppliers and all of the turbines secured to support our projects slated for construction through 2009

        Access to wind turbines is a crucial factor in the ability of wind energy developers to build out their pipeline of projects. As a result of the rapid growth in the wind energy industry, developers are facing increased competition in procuring wind turbines. In order to address this issue, we have built strong relationships with major turbine suppliers and have successfully secured the turbines needed to support our projects slated for construction through 2009. Our exclusive turbine supplier to date has been General Electric, or GE. With over 6,500 GE 1.5 MW wind turbines installed worldwide, GE turbines have an established track record and a solid history of reliability. Each of our operating technicians undergoes an intense training program at the GE Wind Training Center to standardize maintenance practices and minimize variability of our maintenance procedures among our windparks. In addition to GE, we maintain an active dialogue with another turbine supplier, as well as with the suppliers of spare parts for our turbines. As we continue to grow our portfolio, we believe that our strong relationships, scale and purchasing power will enable us to continue to secure the turbines and related spare parts necessary to support our growth on favorable terms with respect to payment, pricing and flexibility.

Substantial local presence and community stakeholder involvement in the markets in which we are active

        We maintain permanently staffed project offices in Altona, Arcade, Bliss, Churubusco and Fredonia, New York; Austin and Hitchland, Texas; Lancaster, New Hampshire; Ubly, Michigan and Rutland, Vermont. By maintaining these offices and becoming involved in local community affairs, we develop a meaningful local presence, which we believe provides us with a significant advantage when navigating the local permitting processes and helps to enlist the support of the local communities for our windparks. We believe that our local approach has enabled us to secure approvals and support for our projects in regions that have historically voiced meaningful opposition and has given us a significant advantage over competitors who are not as active in the local communities in which we are developing windparks.

Business Growth Strategy

        We intend to implement the following strategies to profitably grow our windpark portfolio in the rapidly developing U.S. wind energy market:

Focus development of wind capacity in attractive deregulated and geographically diverse energy markets

        We seek to develop windparks within geographically diverse, established and deregulated energy markets that have attractive energy pricing, strong RPS programs and, in many cases, capacity

5



payments. In implementing this strategy, we have initially focused on New York, Texas, New England and a limited number of other states, which meet this criteria. We intend to expand our operating wind generation portfolio by adding projects adjacent to our existing windparks and by entering into new markets. We believe that this carefully designed expansion plan will allow us to effectively leverage our existing resources while seeking development opportunities in new markets.

Enter regional markets in scale, primarily through organic development

        Upon entering a market, we seek to become a leading wind energy operator and an influential voice within the region. We believe that our large scale projects will enable us to take full advantage of the benefits of our local presence and spread our costs over a large number of turbines. While we may opportunistically acquire existing or partially developed windparks, we expect to grow our portfolio primarily through organic development, which means developing each project in-house, from initial site selection through construction and operation. We believe that our organic development model is generally preferable to acquiring projects because of the time and risk related to finalizing development on a third party's project and the premium these opportunities attract in the current competitive market.

Extract the efficiency benefits of our fully integrated business model

        We seek to maximize project efficiency and reduce costs by taking advantage of our in-house capabilities in development, financing, construction and operations. For example, in the construction phase, we believe our ability to choose between using outside providers and taking advantage of our in-house capability to act as a general contractor provides us significant flexibility in selecting the most cost-effective and strategically efficient option. Additionally, we will maintain a central warehouse of spare parts, which we believe will result in significant benefits, including increased operational flexibility, as we will not have to delay maintenance as a result of waiting for an item with a long-lead time to arrive. As our asset base grows, we believe we will achieve further cost reductions due to economies of scale in maintaining our windparks and purchasing components.

Manage commodity price risk while retaining potential energy value

        We have implemented and expect to continue to implement financial hedges with respect to a significant portion of the energy we produce. The effect of these hedges is to help stabilize our revenue stream by reducing the impact of regional energy spot market price volatility. The long term price protection achieved through our hedging program benefits both us and our lenders by strengthening our ability to provide sufficient debt service coverage and as a result greatly enhances our ability to obtain debt financing under attractive terms. We can still benefit from future increases in power prices through our exposure to commodity prices on the unhedged portion of our energy production both in the initial stages of the project's life (as the actual energy volume generated by the projects is expected to be greater, on average, than the hedged volume) and in the time after the hedging arrangement expires. Furthermore, our strategy of entering into hedges around the time of the closing of financing for a windpark as opposed to pursuing power purchase agreements, or PPAs, allows us to potentially benefit from future energy price movements and avoid the cost and price competition involved in bidding on PPAs.

Utilize debt and tax equity finance structures

        In our selection of the various financing alternatives generally available to wind energy developers, we seek to maximize the rate of return on our project investments and monetize the tax benefits that we currently cannot utilize due to our lack of taxable income. We attempt to finance substantially all of our turbine purchases with debt secured primarily by the turbines themselves in order to increase our flexibility with respect to the specific projects in which turbines will be placed. We also use construction

6



and project debt financing to minimize recourse against the issuer while optimizing our use of third-party capital. Finally, we intend to use tax equity financing arrangements in order to monetize the value generated by the PTCs and accelerated tax depreciation that are available to us as a wind energy generator. We will be able to enter into these arrangements at a cost of capital that reflects the tax equity investor's ability to utilize these tax benefits. Until we have significant taxable income, we intend to continue financing our windparks with tax equity financing structures so long as tax incentives and tax equity investors remain available.

Create relationships as a community stakeholder

        As part of our development strategy, we aim to create strong community relationships that we believe are critical to generating support and securing the land and permits necessary for our windparks. Our team works closely with the landowners who will host the windpark to ensure that they fully understand the impact of having turbines on their property. Throughout the development process, we assess and monitor the landowners' and broader community's receptiveness and willingness to host a windpark in their area. This proactive involvement in the community also enables us to submit permit applications that comply with local regulations while addressing local concerns.

Attract, train and retain top talent

        As we continue to grow our business and add new windparks to our portfolio, we will need to attract, train and retain additional employees. We believe that our collaborative culture, fully integrated management model and internal human resource development abilities are critical to attracting new and experienced talent and retaining key team members, such as our engineers, developers and meteorology experts. We provide extensive training and we believe that we offer an attractive employment opportunity in the markets in which we operate. In addition, as part of our retention strategy, we will be issuing equity incentive awards to certain key members of our team in connection with this offering.

Summary Risks

        There are substantial risks and uncertainties that may affect our financial and operating performance and our growth. You should carefully consider all of the risks discussed in "Risk Factors," which begins on page 13, before investing in our common stock. These risks include the following:

    our limited operating history and the nature of our business;

    our history of operating losses and negative cash flows from operating and investing activities, which we expect to continue through the next several years;

    our dependence on federal tax benefits and state regulatory benefits for renewable energy generation, which may expire or may be modified in a manner that reduces available benefits;

    our ability to successfully implement our windpark development plans;

    our ability to raise sufficient financing on acceptable terms, or at all, necessary to achieve our windpark development plans;

    the vulnerability of our windparks to adverse meteorological and atmospheric conditions;

    delays and cost overruns during the development and construction of our windparks; and

    our ability to successfully operate our windparks.

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Our Sponsors

        Our principal stockholders and sponsors are JPMP Wind Energy (Noble), LLC, an investment fund affiliated with J.P. Morgan Partners, LLC, or JPMP, which is advised by CCMP Capital Advisors, LLC, or CCMP Capital, and CPP Investment Board (USRE II) Inc., an investment fund affiliated with the CPP Investment Board, or CPPIB.

        JPMP is a private equity division of JPMorgan Chase & Co. (NYSE: JPM), one of the largest financial institutions in the U.S. JPMP has invested over $15 billion worldwide in industrial, consumer, media, energy, financial services, healthcare and technology companies since its inception in 1984. In August 2006, the buyout and growth equity investment professionals of JPMP separated from JPMorgan Chase & Co. and formed CCMP Capital, a global private equity firm specializing in buyout and growth equity investments in companies ranging from $500 million to more than $3 billion in size. CCMP Capital has offices in New York and London, and is affiliated with CCMP Capital Asia which has offices in Australia, China, Japan and Korea. CCMP Capital advises JPMP on its portfolio of private equity investments, including the investment by JPMP Wind Energy (Noble), LLC in Noble.

        CPPIB invests the funds not needed by the Canada Pension Plan, or CPP, to pay current benefits on behalf of 17 million Canadian contributors and beneficiaries. In order to build a diversified portfolio of CPP assets, the CPPIB is investing in publicly-traded stocks, private equities, real estate, inflation-linked bonds, infrastructure and fixed income. Based in Toronto, Canada, the CPPIB is governed and managed independently of the CPP and at arm's length from governments. At December 31, 2007, the CPP Fund totaled CDN$119.4 billion, including approximately CDN$11.4 billion invested in private equity and infrastructure investments.

Corporate Reorganization

        Noble was founded in August 2004 by a group including our Executive Chairman, Charles Hinckley and our Executive Vice President, Development, John Quirke.

        We are currently a limited liability company. Our board of managers has approved our conversion into a Delaware corporation in connection with this offering. Pursuant to our corporate reorganization, all of our preferred units and common units will automatically be converted into shares of our common stock, and all shares of our common stock outstanding prior to the completion of this offering will be the result of this conversion.

        In this offering, we will sell shares of our common stock; however, our sponsors will continue to own in the aggregate      % of our common stock (assuming that the underwriters do not exercise their option to purchase additional shares) after the offering. Pursuant to our governance agreements, initially JPMP will have the right to designate       directors (out of a total of      initial board members), and subject to the receipt of regulatory approval from the Federal Energy Regulatory Commission, or FERC, and New York State, CPPIB will have the right to designate       directors. As a result, the sponsors will have the power to control our affairs and policies including with respect to the election of directors (and through the election of directors the appointment of management), the entering into of mergers, sales of substantially all of our assets and other extraordinary transactions. The number of sponsor- designated directors will be reduced as the sponsors' ownership percentage decreases. However, because our board of directors will be divided into three staggered classes and because the sponsors may retain a significant ownership interest in us, the sponsors may be able to influence or control our affairs and policies even after they cease to own a majority of our outstanding common stock.

8


Company Structure

        A summary chart of our company structure showing our main subsidiaries and projects in development, in construction and in operation following the completion of this offering is depicted below.

GRAPHIC

Our Corporate Information

        Our principal executive offices are located at 8 Railroad Avenue, Suite 8, Second Floor, Essex, Connecticut 06426. Our telephone number is (860) 581-5010, and our website address is www.noblepower.com. Information contained on our website does not constitute part of this prospectus.

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THE OFFERING

Common stock offered by Noble Environmental Power, Inc.                     Shares

Common stock outstanding following the offering

 

                 Shares

Underwriters' option to purchase additional shares

 

                 Shares

Use of proceeds

 

We estimate that we will receive net proceeds from this offering of approximately $         million, or approximately $         million if the underwriters exercise their option to purchase additional shares in full, in each case after underwriting discounts and commissions and estimated offering expenses.

 

 

We expect to use the net proceeds from this offering for general corporate purposes, including funding the costs of our corporate and project development activities, the investment of equity into project companies and the funding of other capital expenditures, including future turbine supply agreements. See "Use of Proceeds."

Proposed NASDAQ Global Market symbol

 

"NEPI"

        The number of shares to be outstanding after this offering is based on           shares to be outstanding after giving effect to our corporate reorganization and this offering, and excludes:

    shares that may be issued upon the exercise of options outstanding as of                , 2008; and

    shares that are reserved for issuance pursuant to our equity incentive plan.

        Unless we specifically state otherwise, all information in this prospectus assumes:

    an initial public offering price of $          , which is the midpoint of the price range on the cover of this prospectus; and

    no exercise of the underwriters' option to purchase additional shares of common stock from us.

        Except as otherwise indicated, all information in this prospectus assumes that our corporate reorganization as a Delaware corporation, including the effectiveness of our certificate of incorporation and bylaws and the conversion of our limited liability company units into shares of common stock as described under "Corporate Reorganization," has occurred.

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SUMMARY CONSOLIDATED FINANCIAL DATA

        The following table sets forth our summary consolidated financial data for the periods ended and as of the dates indicated below. We have derived the summary consolidated financial data as of and for the period ended December 31, 2004 from our audited consolidated financial statements that are not included in this prospectus. We have derived the summary consolidated financial data as of December 31, 2007 and for the periods ended December 31, 2007, 2006 and 2005 and for the period from August 31, 2004 (date of inception) to December 31, 2007 from our audited consolidated financial statements included elsewhere in this prospectus.

        The pro forma information included in the table below as of December 31, 2007 represents our balance sheet and earnings per share on a pro forma basis to reflect our corporate reorganization, including the filing of our certificate of incorporation to authorize           shares of common stock and           shares of undesignated preferred stock and the automatic conversion of all of our outstanding limited liability preferred and common units into           shares of common stock as described under "Corporate Reorganization" and on a pro forma as adjusted basis to reflect the sale by us of           shares of common stock in this offering at an assumed initial offering price of $          per share, the midpoint of the range on the cover of this prospectus, after deducting underwriting discounts and commissions and estimated expenses.

        The information set forth below should be read in conjunction with "Selected Consolidated Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements included elsewhere in this prospectus.

 
  Year Ended December 31,
  August 31, 2004
(date of inception)
to December 31,

 
  2007
  2006
  2005
  2004
  2007
 
  (in thousands)
Statement of operations data:                              
  Revenues   $   $   $   $   $
   
 
 
 
 
Operating expenses:                              
  Salaries, wages, employment taxes and fringe benefits     10,627     9,788     2,919     352     23,686
  Write-off of construction in progress     574     5,500             6,074
  General and administrative expenses     8,265     4,024     4,771     733     17,793
  Depreciation     776     492     83         1,351
  New project development     3,625     2,241     10         5,876
  Change in fair value of derivative contract     21,073                 21,073
  Other expense     32     18             50
   
 
 
 
 
  Operating loss     44,972     22,063     7,783     1,085     75,903
  Interest income     2,486     1,384     24         3,894
   
 
 
 
 
  Net loss   $ 42,486   $ 20,679   $ 7,759   $ 1,085   $ 72,009
   
 
 
 
 
Net loss allocable to common unitholders:                              
  Net loss     (42,486 )   (20,679 )              
  Preferred dividend(1)     18,662     4,018                
   
 
 
           
  Net loss allocable to common unitholders   $ (61,148 ) $ (24,696 ) $            
   
 
 
           
Net loss allocable to common unitholders per unit:                              
  Basic and diluted   $ (131.99 ) $ (69.49 ) $            
   
 
 
           

(1)
The preferred dividend was not declared (or paid) during the period from August 31, 2004 (date of inception) to December 31, 2007.

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  Year Ended December 31,
  August 31, 2004
(date of inception)
to December 31,

 
 
  2007
  2006
  2005
  2004
  2007
 
 
  (in thousands)
 
  Weighted average units used in the caculation of net loss per unit allocable to common unitholders basic and diluted     463,260     355,378                  
   
 
 
             
Pro forma net loss data                                
  Net loss allocable to common unitholders as reported   $ (61,148 )                        
  Pro forma adjustment for income tax benefit                              
  Pro forma net loss allocable to common unitholders   $ (61,148 )                        
   
                         
Pro forma basic and diluted net loss allocable to common unitholders per common unit                                
   
                         
Weighted average shares used in pro forma basic and diluted net loss per common share allocable to common unitholders                                
   
                         

Statement of cash flows data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Cash flows provided (used) by operating activities   $ 39,921   $ (20,210 ) $ (6,036 ) $ (1,003 ) $ 12,672  
  Cash flows used by investing activities     (617,867 )   (507,141 )   (47,206 )       (1,172,214 )
  Cash flows provided by financing activities     618,043     532,591     54,375     1,359     1,206,368  
 
 
  As of December 31, 2007
 
  Actual
  Pro Forma
  Pro Forma
As Adjusted

 
  (in thousands)
Balance sheet data:                  
Cash and cash equivalents   $ 46,826   $     $  
Restricted cash     50,401            
Prepaid and other current assets     63,507            
Construction in progress     959,202            
Property and equipment, net     4,653            
Deferred financing costs     15,087            
Construction material deposits     150,259            
Other assets     1,208            
   
 
 
Total assets   $ 1,291,143            
   
 
 

Short-term liabilities

 

$

135,099

 

 

 

 

 

 
Long-term obligations     931,268            
Total liabilities     1,066,367            
Members' equity     224,776            
   
 
 
Total liabilities and equity   $ 1,291,143            
   
 
 

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RISK FACTORS

        Investing in our common stock involves a high degree of risk. You should carefully consider the following risks and all other information contained in this prospectus, including our consolidated financial statements and the related notes, before investing in our common stock. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, also may become important factors that affect us. If any of the following risks materialize, our business, financial condition or results of operations could be materially harmed. In that case, the trading price of our common stock could decline, and you may lose some or all of your investment.

Risks Relating to Our Business and Our Industry

We have a limited operating history and should be viewed as a development stage enterprise.

        We began our business in August 2004 and commenced operation of our first windparks in March 2008. We have a limited operating history from which you can evaluate our business, and our prospects must be considered in light of the risks and uncertainties encountered by development stage enterprises competing in rapidly evolving markets, such as the renewable energy market.

        Some of these risks relate to our potential inability to:

    complete the refinancing of our construction and equity bridge loans;

    obtain all the land rights, turbines, transmission interconnection agreements, permits and approvals needed to construct and operate our windparks;

    obtain adequate financing to develop our windparks;

    construct our planned and future windparks within projected time and cost schedules;

    commence and manage significant operations;

    manage growth in personnel and operations;

    manage our costs as we expand our business;

    recruit and retain key personnel; and

    anticipate and mitigate the other risks described in this prospectus.

If we cannot successfully address these risks, our business, results of operations and financial condition may suffer.

We have not generated revenue and have generated net losses and negative cash flows from investing activities since our inception.

        For 2006 and 2007, we did not generate revenue, we incurred net losses of approximately $20.7 million and $42.5 million, respectively, and our net cash used by investing activities was approximately $507.1 million and $617.9 million, respectively. At December 31, 2007, our accumulated deficit was approximately $72.0 million. We have spent, and expect to continue to spend, significant resources to fund the development and construction of our windparks. To date, our capital expenditures and working capital requirements have been funded by project debt, turbine financings and capital contributions from our sponsors.

        We expect to incur substantial pre-tax losses over the next several years as we develop and construct new windparks, hire additional employees, expand our operations and incur the additional costs of operating as a public company. In addition, factors such as increases in labor or material costs, higher-than-anticipated financing costs for our windparks, non-performance by third-party suppliers or

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subcontractors and major incidents and/or catastrophic events, such as fires, earthquakes or storms, may cause us to experience increased costs with respect to our windparks. As a result, our net losses and accumulated deficit may also increase significantly. We expect to fund our future capital requirements out of cash on hand, operating cash flow, debt and tax equity financing and additional issuances of our equity securities. If we are unable to raise additional capital or generate sufficient operating cash flow, we may have to reduce or terminate our operations.

We are dependent upon the continued and uninterrupted operation of a limited number of operating windparks.

        We currently have only three windparks in operation, and we anticipate having only a limited number of windparks in operation over the next two years. As a result, our operations may be subject to material interruption if any of our windparks is damaged or otherwise adversely affected by one or more accidents, severe weather or other natural disasters. Our windparks may be subject to labor disruptions and unscheduled downtime or other hazards inherent in our industry. Some of those hazards may cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage and may result in suspension or termination of operations and the imposition of civil or criminal penalties. In addition, all of our currently operating windparks are located in New York State. If any of our three operating windparks experiences material interruptions or if the regulatory environment or energy market characteristics in New York were to change in a manner adverse to us, it could have an adverse effect on our business, results of operations and financial condition.

The federal government may not extend or may decrease tax incentives for renewable energy, including wind energy, which would have an adverse impact on our development strategy.

        Current federal tax incentives applicable to the wind energy industry include the PTC and accelerated tax depreciation for certain windpark assets. The PTC currently provides the owner of a wind turbine placed in operation before the end of 2008 with a ten-year credit against its federal income tax obligations based on the amount of electricity generated by the wind turbine. The accelerated depreciation for certain windpark assets provides for a five-year depreciable life for these assets, rather than the 15 to 25 year depreciable lives of many non-renewable energy assets.

        Currently, the PTC is scheduled to expire on December 31, 2008 and will not be available for energy generated from wind turbines placed in service after that date unless extended or renewed by Congress. Recent legislative efforts to extend the PTC have failed, and we cannot assure you that current or any subsequent efforts to extend or renew this tax incentive will be successful or that any subsequent extension or renewal will be on terms that are as favorable as those that currently exist. In addition, we cannot assure you that any subsequent extension or renewal of the PTC would be enacted prior to its expiration or, if allowed to expire, that any extension or renewal enacted thereafter would be enacted with retroactive effect. We also cannot assure you that the tax laws providing for accelerated depreciation of windpark assets will not be modified, amended or repealed in the future. If the federal PTC is not extended or renewed, or is extended or renewed at a lower rate, our financing options will be reduced and our development plans for additional windparks will be adversely affected.

        Even if the federal PTC is extended, we currently expect that we will not have sufficient taxable income to utilize the benefits generated by the federal PTC and there can be no assurance that we will be able to find other suitable tax equity investors interested in monetizing these federal tax benefits who meet our credit risk standards. Moreover, tax equity investors have finite funds, and wind energy producers compete with other renewable energy producers for tax equity financing. In the current rapidly expanding market, the cost of tax equity financing may increase and there may not be sufficient tax equity financing available to meet the total demand in any year. In addition, one or more current tax equity investors may decide to withdraw from this market thereby depleting the pool of funds

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available for tax equity financing. Alternative financing will be more expensive and there may not be sufficient liquidity in alternate financial markets. As a result, our development plans for additional windparks would be adversely affected.

Our use of tax equity financing structures will place certain limits on our project subsidiaries' operational flexibility and our rights to the cash flow generated by the windparks.

        We expect to finance our windparks with a tax equity financing structure. Under this structure, the tax equity investor is a member holding equity in the limited liability company that directly or indirectly owns the windpark. Our relationship with the tax equity investor will be governed by an operating agreement, under which we manage the day to day operations of the subsidiary, subject to the tax equity investor's right to approve the project's annual operating budget and most major management decisions. These approval rights include decisions regarding capital expenditures above certain levels, replacement of major contracts, bankruptcy and the sale of a windpark. As a result, the tax equity investor may prevent us from making certain business decisions that may be beneficial to us.

        In addition, the operating agreement typically will provide that for a period of time, all of the cash flows from the windpark will be distributed to the tax equity investor until it realizes a specified target rate of return, taking into account cash distributions, as well as the tax benefits and tax costs of its equity investment in the project. As a result, this structure reduces the cash flows available to us for other uses, and the period during which the tax equity investor receives all of the cash flows may last longer than expected if our windparks perform below our expectations.

Our development plan requires substantial additional capital, and we may be unable to raise financing when needed or on acceptable terms, which could force us to delay, reduce or eliminate some or all of our development plans.

        Each of our windparks under development and any additional windparks that we may seek to develop will require substantial capital investment. As a result, our continued access to capital on acceptable terms is necessary for the success of our development strategy. Our windparks are currently financed primarily using capital contributions from our sponsors and project financing structures, consisting of non-recourse or limited recourse debt. We intend to continue financing our windparks with project finance debt and, so long as tax incentives and tax equity investors are available, with tax equity finance structures, as well as with additional issuances of common stock.

        Market conditions and other factors, however, may not permit future financings on terms similar to those we have obtained to date or at all. Our ability to arrange for project financing on a substantially non-recourse or limited recourse basis or tax equity financing and the costs of such capital are dependent on numerous factors, including general economic and capital market conditions, credit availability from lenders, investor confidence, the adequacy of our equity investment in each windpark, our ability to forward sell or hedge the energy to be produced by the windpark, the success of our then-current windparks, the credit quality of the windparks being financed and the existence of regulatory and tax incentives that are conducive to raising capital.

        If we are unable to obtain financing for our windparks on a non-recourse or limited recourse basis, we may attempt to finance them by selling additional equity securities, which would cause dilution of our common stock. We can give no assurance, however, that any effort to sell additional securities will be successful or will raise sufficient capital to finance additional windparks. In the absence of available or acceptable financing, we may be required to delay, reduce or eliminate some or all our development plans.

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Our financial performance depends on policies and regulatory frameworks that support renewable energy development.

        The development and financial performance of our windparks are significantly dependent on state policies and regulatory frameworks that support windpark development. The states in which we are developing and plan to develop windparks currently provide various types of incentives that support the sale of electricity generated from wind energy. These policies include RPS requirements, which impose renewable energy purchase obligations or targets on electric utilities and other retail energy suppliers. We cannot assure you that government support for renewable energy will continue, or that the electricity produced by our future windparks will continue to qualify for support through these RPS programs. The elimination of, or reduction in, state government policies that support renewable energy could have an adverse impact on our results of operations, financial performance and our future development efforts.

Our high levels of indebtedness could adversely affect our business.

        We have high levels of indebtedness. As of December 31, 2007, we had approximately $926.8 million of total consolidated indebtedness, of which approximately 70% represented non-recourse and limited recourse debt. We expect to continue to have significant debt and interest expense for the foreseeable future.

        The majority of our indebtedness relates to the acquisition of wind turbines and the construction of our windparks. The project financing that we use to fund the construction and operation of our windparks is limited recourse, and payment of the interest and principal on the financing is made primarily from the revenues generated by the windpark once operations commence through the sale of energy, capacity and RECs, as well as the monetization of certain federal tax benefits available to us.

        Our project and turbine financing documents contain covenants consistent with market practice that impose significant restrictions on the way we operate our business, including restrictions on our ability to:

    incur additional indebtedness or guarantee indebtedness of others;

    make certain loans or investments;

    pay distributions or dividends to our stockholders, and receive distributions from our subsidiaries;

    repurchase shares of our common stock; or

    sell our assets.

These covenants could limit our ability to finance our future operations and capital needs and our ability to pursue other business activities that may otherwise be in our interest.

        Moreover, under our turbine financing agreements, most of our wind turbines and the equity interest in certain of our project subsidiaries are subject to first and second ranking security interests. As a consequence, even if we are permitted to incur additional debt under our existing financing agreements, to the extent any such financing would require security, we may have difficulty obtaining or may not be able to obtain financing because our available unsecured assets are insufficient to secure such debt. For additional information see "Description of Certain Financing Arrangements—Senior Secured Turbine Credit Facilities."

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If our project subsidiaries default on their obligations under their non-recourse or limited recourse project finance debt, the issuer may be required to make certain payments to the relevant lenders and these lenders may foreclose on the collateral securing this debt, which could cause us to lose certain of our windparks.

        The debt for our windparks is non-recourse or limited recourse project finance debt. Non-recourse project finance debt refers to debt that is repaid solely from the project's revenues and is secured by the project's physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. Limited recourse project finance debt refers to the issuer's additional commitment to provide limited financial support to the project subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. If our project subsidiaries default on their debt service obligations under the relevant project finance agreement, creditors of a limited recourse project financing will have direct recourse to the issuer to the extent of the issuer's limited recourse obligations. This may require the issuer to use distributions received by the issuer from other subsidiaries as well as other sources of cash available to us to satisfy these obligations. In addition, if our project subsidiaries default on their debt service obligations under the relevant project finance agreement and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or the project subsidiary would only retain an interest in the relevant windpark, if any, remaining after all debts and obligations were paid in full. The loss of our ownership interest in one of or more our project subsidiaries would have a material adverse effect on our business, results of operations and financial condition.

We currently rely extensively on one of a small number of wind turbine manufacturers. Because demand for wind turbines and related components has increased significantly, we may face difficulties in obtaining or be unable to obtain delivery of wind turbines and related components at affordable prices or in a timely manner, which could have a material adverse effect on our business prospects, results of operation and financial condition.

        There is a small number of companies that have the expertise and access to the necessary components to build multi-megawatt class wind turbines. We currently have contracts in place with GE to purchase all of the required wind turbines for all of our windparks slated for construction through 2009. However, we have not yet contracted for wind turbines for our windparks in development for 2010 and subsequent years.

        The rapid growth in aggregate worldwide windpark installed capacity over the past five years, as well as the large number of windparks currently in-development, has created a surge in the demand for wind turbines and their related components that is currently not satisfied by suppliers. Wind turbine suppliers like GE have significant supply backlogs, which tend to drive up prices and delay the delivery of ordered wind turbines and components. Any delays in the delivery of ordered wind turbines and components may delay the successful completion of our windparks under development. Additionally, price increases may make it more costly for us to acquire wind turbines that are not covered by our current turbine supply agreements.

        We can provide no assurance that we will, in the future, be able to purchase a sufficient quantity of turbines and other technical equipment to satisfy our business plans, or that wind turbine and other component manufacturers will not give priority to other market participants, including our competitors. To the extent that GE or any other alternative wind turbine manufacturer becomes unable or unwilling to supply us with the wind turbines that we need to develop, construct and operate our windparks in accordance with our development plan and budget, we may be unable to find suitable replacements. If we are unable to acquire turbines to meet our development plan, it would have a material adverse effect on our business prospects, results of operations and financial condition.

17


The wind energy industry is characterized by intense competition, and we encounter competition from other wind power producers that could materially and adversely affect our business, results of operations and financial condition.

        We face significant competition from other wind energy developers and operators, and this competition may intensify in the future. We compete primarily for a limited number of sites that are desirable for windparks based on our development criteria. We also compete for the limited supply of wind turbines and other key equipment necessary to construct and operate our facilities. We also compete to recruit executives and employees, but may not succeed in doing so as we do not offer significantly greater salaries or benefits than any of our competitors. Moreover, our offices tend to be located in rural areas, which offer limited job opportunities for spouses of the executives and employees we seek to attract.

        Certain of our competitors have more experience in the wind energy industry, as well as much greater financial, technical or human resources than we do, which may limit our ability to compete effectively with them and to acquire or improve our market share. In particular, certain competitors who seek to expand in the renewable energy sector, including established producers in Europe and large utilities in the U.S., have greater financial strength than we do, which enables them to acquire new projects at higher prices and to purchase market share in the industry. We cannot assure you that we will be able to succeed in the face of current or future competition.

Our windpark development activities may be unsuccessful or delayed despite the expenditure of significant amounts of capital and management time and energy.

        Our success in developing a particular windpark is contingent upon, among other things, acquisition of rights to all necessary land parcels, receipt of required local, state and federal permits and the negotiation of satisfactory turbine supply, engineering and construction, interconnection agreements and financial commodity hedges or power purchase arrangements. We may fail to accomplish some or all of these milestones or may not accomplish them on a timely basis. In addition, we may modify the stated timing, size and geographic location of the windparks that are currently in development or that we may develop in the future. The development of a windpark typically requires us to incur significant expenses for land-rights acquisition, permits and legal and other services before we can determine whether a project is environmentally feasible, economically attractive or capable of being financed. For instance, we generally do not initiate the studies needed for an environmental impact study until approximately 18 months prior to the anticipated start date for the construction of a windpark.

        Currently, we have 34 identified windparks at various stages of development, and we intend to pursue the development of other windparks. Our successful development of these windparks is subject to substantial risks, including:

    failure to obtain adequate real estate rights;

    changes in the regulatory environment;

    adverse changes in energy, capacity or REC market prices or liquidity that materially impacts our projected revenues;

    unexpected environmental issues;

    local community opposition to our proposed windparks;

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    failure to secure and maintain required regulatory, environmental and other necessary permits or approvals; and

    failure to obtain approvals from transmission system operators for the interconnection of our windparks with their facilities or the excessive costs of interconnection.

Any of these factors could lead to the termination of the development of a windpark after the incurrence of significant expense.

We may be unable to timely complete the construction of our windparks, and our construction costs could increase to levels that could make a new windpark too expensive to complete or too unprofitable to operate.

        We experienced delays in the completion of the Initial New York Windparks and the total construction cost of these windparks exceeded our initial budget. We may suffer significant construction delays or construction cost increases as a result of a variety of factors, including:

    failure to receive turbines or other critical components and equipment from third parties on schedule and according to design specifications;

    failure to complete interconnection to transmission networks;

    failure to receive quality and timely performance of third-party services;

    increases in prices of goods and services;

    failure to secure and maintain required regulatory and environmental permits or approvals;

    inclement weather conditions;

    adverse environmental and geological conditions;

    unexpected environmental issues;

    work stoppages or other labor disturbances;

    shortages of labor;

    personal injury or loss of life of our employees; and

    force majeure or other events out of our control with respect to our windparks.

Any of these factors could give rise to construction delays and construction costs in excess of our budgets, which could prevent us from completing construction of a windpark, cause defaults under our financing and revenue arrangements and impair our business, results of operations and financial condition.

        In addition, significant construction delays may also result in the loss of revenues expected to be generated by our windparks. For example, we have entered into contracts to sell certain of the RECs to be generated through the operation of our New York windparks to the New York State Energy Research and Development Authority, or NYSERDA, the entity that administers the central procurement of RECs for the state of New York. Pursuant to our contracts with NYSERDA regarding our Altona, Bellmont and Chateaugay windparks currently in development, our ability to sell the RECs generated by our operation of these windparks may expire if the windparks are not in operation by November 2008.

Delays in the commencement of operations of our windparks may increase our maintenance and operations costs.

        Delays in the commencement of operations of our windparks may result in increased operations and maintenance costs relating to routine maintenance or defects in the wind turbines at a windpark.

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Our turbine manufacturer provides a warranty on each wind turbine; however, the warranty period ends the earlier of 24 months from the date the wind turbine is placed into commercial operation or 39 months from the date the wind turbine is delivered to us. For example, due to development delays, we may have less than one year remaining on the manufacturer's warranty for the wind turbines that will be installed at our Altona windpark which is currently in construction and scheduled to commence operation during the fourth quarter of 2008.

The performance of our windparks is vulnerable to adverse meteorological and atmospheric conditions.

        The production of electricity generated by our windparks will be the source of substantially all of our revenues. As a result, our results of operations will be highly dependent on meteorological and atmospheric conditions.

        When we develop a windpark, we evaluate the quality of the wind resources at the selected site by a number of means, and we retain third-party experts to assist us in these evaluations. We use the wind data that we gather on site and data collected through other sources to develop wind resource projections for the windpark's performance, revenue generation, operating profit, project debt capacity, project tax equity capacity and return on investment, which are fundamental elements of our business planning. Wind resource projections at the time of commercial operations can have a significant impact on the level of third-party capital that we can raise, including the expected contributions by tax equity investors. We expect to commence commercial operations in connection with term conversion, which is discussed in more detail under "Description of Certain Financing Arrangements."

        Our wind resource projections do not predict the wind at any specific period of time in the future. Therefore, even in the event where our prediction of a windpark's wind resources becomes validated over time, the windpark will experience hours, days, months, and even years that are below our wind resource predictions.

        Our wind resource projections may not predict the actual wind resources observed by the windpark over a long period of time. Assumptions included in our wind resource projections, such as the interference between turbines, effects of vegetation and land use, and terrain effects may not be accurate. Our wind resources average monthly and average time of day long-term predictions may not be accurate and, therefore, the energy our windparks produce over time may have a different value than we had forecast. If as a result of inaccurate wind resource projections, the performance of one or more of our windparks falls below our projected levels, our business, results of operations and financial condition could be materially adversely affected.

Operational factors may reduce energy production below our projections, causing a reduction in revenue.

        The amount of electricity generated by a windpark depends upon many factors in addition to the quality of the wind resources, including but not limited to turbine performance, aerodynamic losses resulting from wear on the wind turbine, degradation of other components, icing or soiling of the blades and the number of times an individual turbine or entire windpark may need to be shut down for maintenance or to avoid damage due to extreme weather conditions. In addition, conditions on the electrical transmission network can impact the amount of energy we can deliver to the network. We cannot assure you that any windpark in our portfolio will meet our energy production expectations in any given time period.

        If our windpark energy projections are not realized, we could face a number of material issues, including:

    our sales of energy may be significantly lower than we forecast;

    the amount of capacity we would be permitted to sell from our facilities may be lower than we forecast;

20


    our energy hedging arrangements may be adversely affected;

    to the extent that we have entered into agreements for the sale of RECs with performance obligations based on our projected production, we may be unable to meet the obligations of these agreements, and as a result could receive less revenue than forecasted from sales of RECs;

    we will be entitled to fewer PTCs than projected, which could, to the extent that we have tax equity financing in place, result in a reduction of payments from our tax equity investors in certain of our tax equity financing structures and an extension of the time period during which our tax equity investors receive the cash flow from our windparks; and

    our windparks may not generate sufficient cash flow to make payments on principal and interest as they become due on our project financings.

As we expand our operations, we may be unable to manage the development, construction and operation of future windparks effectively.

        Our planned expansion and any additional future expansion will place significant demands on our management, personnel, systems and resources. We plan to significantly increase our development, construction and operation of windparks and to hire additional employees to support these increases. To successfully manage our growth and handle the responsibilities of being a public company, we believe we must effectively:

    hire, train, integrate and manage additional construction, operations and finance personnel;

    retain key executives and augment our management team;

    implement and improve administrative, financial and operational systems, procedures and controls;

    expand and upgrade our technological capabilities; and

    manage relationships with our landowners, suppliers and other third parties.

We may encounter difficulties in effectively managing these and other issues presented by rapid growth. If we are unable to manage our growth effectively, we may not be able to take advantage of market opportunities, execute our business plan or respond to competitive pressures.

The number of desirable sites available for the development of windparks is limited, and our inability to identify or acquire sites will limit our ability to implement our development strategy.

        Windparks can be built only in regions with suitable wind conditions. In addition, certain constraints must be taken into account in connection with the development of each windpark. These include topographic constraints, landowners' willingness to grant us access to their land, connection capacities of the local transmission network and regulatory constraints associated with the proximity to housing, airports, protected sites or viewsheds.

        If these constraints on the development of windparks increase or if we cannot find or acquire sufficient available sites on which to develop our windparks, it could have a material adverse effect on our business, results of operations, financial condition, or on our ability to implement our business strategy.

We may be unable to obtain control of and access to the real estate that we need for the construction and operation of our windparks.

        Windpark facilities, which include turbines, electrical collection systems and substations, are spread over large areas of land. We obtain rights to use land owned by others through leases, easements and other arrangements. If we are unable to secure the land rights we need at reasonable cost, we may have to redesign our projects, which may result in increased development and construction costs and delays in completing the windpark. In addition, we may be required to cancel or reduce the scope of a project if we cannot obtain all of the real estate interests.

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The access to, availability and cost of transmission networks for our windparks are critical to our development efforts.

        We will depend on electric transmission facilities owned and operated by third parties to deliver the electricity that we will sell. We typically will not own or control the transmission facilities other than the limited facilities necessary to connect our windparks to the transmission network. The capacity of the local transmission network may be limited or constrained, and the owner of the network may not allow us to interconnect a new windpark without first constructing the system upgrades that the owner requires. For this reason, we expect to pay some or all of the costs of upgrading the existing transmission facilities to support the additional electricity that our windpark will be delivering into the network. The location of a windpark in a particular area therefore depends significantly on whether it is possible to interconnect with the transmission network at a reasonable cost. Many of our windparks in development will be located in remote areas with limited transmission networks where intense competition exists for access to, and use of capacity on, the existing transmission facilities. We cannot assure you that we will obtain sufficient network connections for future windparks within planned timetables and budgetary constraints.

        Our windparks are required to meet certain technical specifications in order to be connected to the transmission network. If any of our windparks do not meet, or cease to comply with, these specifications, we will not be able to connect, to or remain connected, to the transmission network. We may also incur liabilities and penalties, including disconnection from the network, if the transmission of electricity by one or more of our windparks does not comply with applicable technical requirements. In the interconnection agreements between our windparks and the applicable transmission owner and/or operator, the transmission owner and/or operator retain(s) the right to interrupt or curtail our transmission deliveries as required in order to maintain the reliability of the transmission network. We have no assurance that our windparks will not be adversely impacted by any such interruption or curtailment.

We may incur delays in the process of negotiating our interconnection agreements for our windparks.

        Our windparks must apply for and obtain interconnection service from the owners and/or operators of the transmission networks in the areas where we propose to develop windparks. In all of the regions where we are developing windparks, we are required to perform studies of the interaction between our windparks and the transmission network in order to satisfy the local transmission owner's and/or operator's technical criteria for interconnecting a new power supplier. The results of these studies will establish the nature and cost of the interconnection facilities that will be necessary to support the interconnection. In most of the regions where we plan to build windparks, the study process is governed by a set of interconnection rules imposed by FERC. These rules generally provide that once a developer has completed the technical study process and defined the facilities that are necessary to accomplish the interconnection, the developer has a right to interconnect the new facility, subject to the negotiation of an interconnection agreement that is acceptable to the owner and operator of the transmission system. We have in the past and may in the future experience delays in completing the negotiation process and executing interconnection agreements for our windparks. The reasons for these delays include, but are not limited to, our inability to deploy sufficient engineering resources to complete the design of the interconnection facilities in the time frames needed to support our construction schedules; the transmission owner's allocation of resources to other projects; the complexity of the system upgrades that may be needed at a particular location; variations in the technical specifications that different transmission owners may apply; and the activities of competitors, who may, under some circumstances, be treated as parties to an interconnection agreement negotiation under the applicable FERC rules. In addition, if we fail to meet the study process milestones set by the rules, we may lose our position in the transmission planning queue, with the possible result that our windparks may be required to restart the study process.

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The transmission networks to which our windparks connect may fail or experience downtime, which will cause us to lose revenue.

        Transmission networks may experience congestion, outages or technical incidents, and operators of these networks may fail to meet their contractual transmission obligations or terminate the contracts involved. Moreover, if the interconnection or transmission agreement of a windpark is terminated for any reason, we may not be able to replace it with an interconnection and transmission arrangement on terms as favorable as the existing arrangement or at all, or we may experience significant delays or costs in connection with securing a replacement.

        If a network to which one or more of our windparks is connected experiences "down time," the affected windpark may lose revenue and be exposed to non-performance penalties and claims from its customers. These may include claims for damages incurred by customers, such as the additional cost of acquiring alternative electricity supply at then-current spot market rates. In addition, network downtime may also reduce the amounts we receive under the terms of any agreement to sell the RECs associated with the windpark. The owners of the network will not usually compensate electricity generators, including our windparks, for lost income due to down time.

We rely on third parties to provide the working capital necessary to run our business.

        We require funds for working capital to pay for our ordinary course expenses, including salaries and benefits for our employees, and professional services fees. We have not yet begun to generate revenue from our windparks. Therefore, our working capital requirements to date have been funded by project-level debt and capital contributions from our sponsors. Because our project-level debt obligations reduce the availability of cash flow from operations, we do not expect that we will generate sufficient cash from our windparks to satisfy all of our working capital needs for the foreseeable future. If we are unable to borrow additional funds or obtain additional capital from existing or future investors, our existing working capital would be depleted, which would have a material adverse effect on our business.

Revenues from our windparks are exposed to fluctuating market prices for energy and capacity.

        Although our strategy involves executing financial hedges designed to limit our exposure to fluctuations in energy prices, a portion of the revenues that our windparks will generate are unhedged and therefore depend on market prices of energy in competitive wholesale energy markets. Market prices for both energy and capacity are volatile and depend on numerous factors outside our control including economic conditions, population growth, electrical load growth, government and regulatory policy, weather, the availability of alternate generation and transmission facilities, balance of supply and demand, seasonality, transmission and transportation constraints and the price of natural gas and alternative fuels or energy sources. The wholesale power markets are also subject to market regulation by the Federal Energy Regulatory Commission, or FERC and independent system operators, or ISOs, or regional transmission operators, or RTOs, which can impact market prices for energy and capacity sold in such markets, including by imposing price caps, mechanisms to address price volatility or illiquidity in the markets or system instability and market power mitigation measures. We cannot assure you that market prices will be at levels that enable us to operate profitably or as anticipated. A decline in electricity or capacity market prices below anticipated levels could have a material adverse impact on our revenues or results of operations. In markets where our windparks qualify to receive capacity payments, it is typical that only a portion of the windpark's capacity is eligible to receive capacity payments. This portion is typically based on the previous year's average net capacity factor during peak periods. In addition, changes to regulatory policy or market rules regarding the qualification of wind generation as a capacity resource could limit or eliminate each of our windparks' ability to receive payments for its generating capacity.

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The price at which we can sell RECs is subject to change, which may have an adverse effect on our results of operations, financial condition and business prospects.

        Although we have agreed to sell some of our RECs at fixed prices under existing agreements with NYSERDA, portions of the RECs we expect our windparks to generate are not yet or will never be under contract and will be subject to the availability of contracts and changes in market prices. Additionally, under the terms of our contracts with NYSERDA, our ability to sell RECs to NYSERDA from our Altona, Bellmont and Chateguay windparks could be terminated if those windparks are not in operation by November 2008. Any increases in the market supply of RECs or changes in state and federal regulatory policy may decrease our ability to sell RECs in the volumes we forecast or could reduce the sales price of our RECs.

Our hedging strategy may not adequately minimize market risk, may expose us to significant losses and may limit our ability to benefit from higher electricity prices.

        We use and plan to continue using derivative financial instruments, such as our hedging agreement with Credit Suisse Energy LLC, or Credit Suisse, an affiliate of Credit Suisse Securities (USA) LLC, to manage market risks and reduce our exposure to fluctuating electricity prices. These activities expose us to certain market risks, including unsuccessful matching of exposures or execution of our hedging strategy, and limit our ability to realize the full benefits of increases in energy prices. Our hedging strategy may not be effective in controlling risk within prescribed boundaries or limits as expected. In addition, future changes in markets may not be consistent with our historical data or assumptions. If we are not able to successfully anticipate and hedge against market risks, volatile electricity prices may have a material adverse effect on our business, results of operations and financial condition.

The majority of our current indebtedness bears interest at variable rates, and is therefore subject to interest rate fluctuations. Our interest rate hedging policy may be insufficient to cover the risk of these fluctuations, which may have a material adverse effect on our results of operations, financial condition and business prospects.

        The majority of our current indebtedness bears interest at variable rates, typically based on the London Interbank Offered Rate, or LIBOR. We manage interest rate fluctuation risk on our project financing debt by entering into long-term interest rate swaps, which, at December 31, 2007, had a notional value of $229.1 million. We cannot assure you that our interest rate hedging policy will be effective against future interest rate fluctuations, which may have a material adverse effect on our cash flows, results of operations and financial condition.

If operating costs exceed those projected for any windpark, the cash flow available from that windpark will be adversely affected, which may have an adverse impact on our results of operations and financial condition.

        Our windparks are exposed to numerous operational risks including the impact of force majeure events, turbine breakdowns, electricity network and other utility service failures and other unanticipated events. The cost of repairing or replacing damaged equipment may be considerable, while repeated or prolonged interruption may result in termination of contracts, substantial litigation and damages or penalties for regulatory or contractual non-compliance, reduced cash flows and increased financing costs. Moreover, these amounts may not be recoverable under insurance policies or contractual claims and, in relation to network failures, network service providers and market operators may also benefit from limitations on liability, which would reduce any recovery of damages from them.

        In addition, our wind turbines and associated equipment also require routine maintenance in order to continue to function properly. We only recently commenced operation of our first windparks and if the level of maintenance and capital expenditure exceeds our projected or contracted level, the cash flow available from the projects will be reduced, which may have an adverse impact on our results of operations and financial condition.

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Spare parts for wind turbines and key pieces of electrical equipment may be unavailable to us.

        We may be unable to obtain spare parts for our wind turbines. The sources for two significant spare parts for wind turbines, namely gear boxes and blades, are located outside of North America. If we were to experience a serial failure of either spare part we would incur delays in waiting for shipment of these items to delivery ports in the U.S. In addition, we do not carry spare substation main transformers. These transformers are designed specifically for each windpark, and the current lead time to order this equipment is approximately one year. If we have to replace any of our transformers, we would be unable to sell electricity from the affected windpark for over a year.

Our windparks' use and enjoyment of real property rights obtained from third parties may be adversely affected by the rights of lienholders and superior leaseholders of the grantors of these real property rights.

        Each of our windparks will be located on land occupied pursuant to various easements and leases. Our rights pursuant to these easements and leases allow us to install wind turbines and related equipment and transmission lines for the windpark and to operate the windpark. The ownership interests in the land subject to these easements and leases may be subject to mortgages securing loans or other liens (such as tax liens) and other easement and lease rights of third parties (such as leases of oil, gas, coal or other mineral rights) that were created prior to our easements and leases. As a result, our rights under these easements or leases are subject and subordinate to the rights of such third parties.

        A default by a landowner at one or more of our windparks under a mortgage could result in a foreclosure on the landowner's property and thereby terminate our easements and leases required to operate the windpark. Similarly, it is possible that another type of lienholder, such as a government authority having a tax lien, could foreclose upon a parcel and take ownership and possession of the portion of the windpark located on the parcel. In addition, the rights of a third party pursuant to a superior lease could result in damage to or disturbance of the equipment at a windpark, or require relocation of windpark assets.

        If any of our windparks were to suffer the loss of all or a portion of its wind turbines or related equipment as a result of a foreclosure by a mortgagee or other lienholder of a land parcel, or damage arising from the conduct of superior leaseholders, our operations and revenues may be adversely affected.

Our insurance coverage may be insufficient to cover losses we may incur as a result of the construction and operation of our windparks.

        We are exposed to risks inherent in the construction and operation of windparks, such as natural disasters, breakdowns and manufacturing defects that could harm persons and damage property. We have obtained insurance coverage for the principal risks of our business. However, we cannot assure you that our insurance policies are or will be sufficient to cover possible losses resulting from natural disasters, breakdowns or manufacturing defects. If we were to sustain a serious uninsured loss or a loss exceeding the limits of our insurance policies, the resulting costs could have a material adverse effect on our business prospects, results of operations and financial condition.

        Our insurance policies provide for our premiums to be adjusted annually. If the premiums we pay for the policies covering our windparks increase significantly, we may be unable to maintain the same level of coverage we currently carry, or we will incur significantly greater costs to enjoy the same level of coverage, including through higher deductibles. Any of these circumstances could have a material adverse effect on our business prospects, results of operations and financial condition.

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We will be required to dismantle wind turbines and other components when a windpark ceases operations.

        In certain jurisdictions in which we plan to develop windparks, we may be under a legal or contractual obligation to dismantle our windparks and restore the site when we cease operation. In the case of our Bliss, Clinton and Ellenburg windparks, we have entered into agreements with each of the towns in which the windparks are located. Under the terms of these agreements, the towns may require us to dismantle the windparks if we violate local laws that apply to the windparks. Prior to commencing operations at the Bliss, Clinton and Ellenburg windparks, we posted security in an amount equal to the estimated cost of dismantling the wind turbines and restoring the related land, including the removal of access roads and the seeding and revegetating of the land. The amounts are subject to annual adjustment by the towns. We expect to enter into similar agreements for future windparks that we develop.

        If the costs to dismantle a windpark and restore the related land exceed the amount that we project, including the annual adjustments that are required under the Bliss, Clinton and Ellenburg agreements, it could have an adverse impact on our business, results of operations and financial condition.

We are exposed to certain risks in relation to our operating model and information technology and systems.

        We rely upon certain technologies and systems for the operation of our businesses. Our operations depend on the efficient and uninterrupted operation of our computer systems that remotely control our operating and maintenance activities. A failure of our network or data gathering procedures, data viruses or attacks by computer "hackers" or other technological problems at our National Operations Center in Plattsburgh, New York, could impede the processing of data, delivery of services and the day-to-day management of our business and could result in disruptions in our operations. In addition, any failure by our information technology systems to connect our National Operations Center to the local control and information systems at each windpark may result in one or more windparks not being operated at optimal efficiency levels or at all until we become aware of a failure, which, in turn, could have a material adverse effect on our business, results of operations and financial condition.

Our ability to obtain and maintain regulatory approval, licenses and permits for the development, construction and operation of our windparks is critical to our future success.

        Each of our windparks must comply with numerous federal, regional, state and local regulations in the course of development, construction and operation. The process of obtaining and maintaining authorization for the development, construction and operation of a windpark is complicated. The authorization process involves a number of state and local governments and agencies, each responsible for evaluating the project, including by means of an environmental impact assessment. Local governments issue the relevant approvals, licenses and permits, including development and operation concessions and building permits.

        We cannot assure you that we will be able to obtain all of the approvals, licenses and permits required to develop, construct and operate windparks that are under development or that we may develop in the future. We may also be unable to maintain the approvals, licenses and permits necessary to continue operating our windparks. If we fail to obtain or maintain the necessary regulatory approvals, licenses or permits, our business prospects, results of operations and financial condition would be materially adversely affected.

Public opposition toward windparks may make it more difficult for us to obtain the necessary permits and authorizations required to develop or maintain a windpark.

        Public attitude towards the aesthetic and environmental impacts of wind energy projects impacts our ability to develop our windparks. In many states and localities, the environmental impact review process ensures a role for concerned members of the public that can lead to changes in design or

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layout, extensive impact mitigation requirements, or even the rejection of a project. In some of the regions where we are developing or plan to develop windparks, local acceptance is critical to our ability to obtain and maintain necessary permits and approvals. We can provide no assurance that any of our projects under development will be accepted by the affected population. Public opposition can also lead to legal challenges that may result in the invalidation of a permit or, in certain cases, the dismantling of an existing windpark as well as increased cost and delays.

        Reduced acceptance of windparks by local populations, an increase in the number of legal challenges or an unfavorable trend in the outcome of these challenges could prevent us from achieving our development plans, which, in turn, could have a material adverse effect on our business, results of operations and financial condition.

Our costs of regulatory compliance are significant and any non-compliance with, or changes in, applicable laws or regulations may result in liabilities or increased costs that could materially and adversely affect our business, results of operations and financial condition.

        Our legal and regulatory compliance costs and obligations in connection with the development, construction and operation of our windparks are substantial. For example, some of the environmental permits and governmental approvals that have been issued for our projects contain conditions and restrictions, including restrictions or limits on the disturbance of wetlands, the disruption of wildlife and noise impacts. We expect the permits issued in the future for our projects in development will contain similar requirements. If we fail to comply with these restrictions, or with any other regulatory standards, we may become subject to regulatory enforcement actions and the operation of our windparks could subject us to fines, penalties, additional costs or the inability to renew, maintain or obtain all required environmental permits and governmental approvals.

        Any decision by the governmental authorities to deny the issuance of or revoke permits or approvals, or our inability to comply with the applicable regulatory requirements, may result in increased compliance costs, the need for additional capital expenditures, a suspension of our windpark operations and development or a default under certain material contracts or our project financing agreements, which could have a have a material adverse effect on our business, results of operations and financial condition.

Our financial performance may be adversely affected by changes in the energy laws and regulations that apply to our windparks.

        We are subject to numerous federal and state energy laws and regulations, including without limitation, the Federal Power Act, or FPA, the Energy Policy Act of 2005, the Public Utility Holding Company Act of 2005, or PUHCA, and the Public Utility Regulatory Policies Act, or PURPA. Changes in applicable energy laws or regulations, or in the interpretations of these laws and regulations, could result in increased compliance costs or the need for additional capital expenditures. If we fail to comply with these requirements, we could also be subject to civil or criminal liability and the imposition of fines. Federal and state energy policies, law and regulation supporting the creation of wholesale energy markets is currently, and may continue to be, subject to challenges, modifications and restructuring proposals, which may result in limitations on the commercial strategies available to us for the sale of our power.

        Under the FPA, FERC regulates wholesale sales of electricity and the transmission of electricity in interstate commerce by "public utilities" as defined under the FPA and places constraints on the conduct of their business, including, among other things, rate and corporate regulation. In addition, we are subject to regulation by state agencies with respect to the operation of our windparks.

        In order for each of our windparks to make wholesale sales of electric energy and capacity at negotiated or market rates, it needs the authorization of FERC. Wholesale sellers authorized by FERC to sell at market-based rates may obtain waivers or blanket pre-approvals as to certain of the regulatory

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requirements of the FPA, including waiver of FERC's accounting regulations and blanket pre-authorization to issue securities and assume liabilities. If certain conditions are not met, FERC has the authority to revoke or revise market-based rate authority and require sales to be made based on cost of service rates. While each of the Initial New York Windparks and certain of our other windparks have obtained such market-based rate authorization from FERC, there is no guarantee that regulatory or other changes will not result in limitation or the loss of such authorization or prevent our other windparks from obtaining such authorization. A loss of our market-based rate authority could have a materially negative impact on our business. Even where market-based rate authority has been granted, FERC may impose various forms of market mitigation measures, including price caps, bidding rules and operating restrictions, where it determines that potential market power might exist and that the public interest requires such potential market power to be mitigated.

        In addition, PUHCA provides, in relevant part, that any entity that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a "public utility company" (which is defined to include an "electric utility company") or a company that is a "holding company" of a public utility company or public utility holding company, is subject to certain regulations granting the FERC access to books and records and oversight over certain affiliate transactions. State regulatory commissions may in some instances also have access to books and records of holding companies. Entities that are holding companies solely by virtue of their ownership of qualifying facilities, or QFs, and exempt wholesale generators, or EWGs, are exempt from FERC access to books and records under PUHCA. In order to obtain EWG status pursuant to PUHCA, the owner of a generating facility must demonstrate that it is engaged directly, or indirectly through one or more affiliates, and exclusively in the business of owning and/or operating facilities used exclusively for the generation of electricity for sale at wholesale. In order to obtain QF status pursuant to PURPA, a generating facility must qualify as a small power production facility or cogeneration facility that has either filed a self-certification of QF status with, or has received a QF certification order from, FERC. A wind generation facility may qualify as small power production facility QF if it is less than 80 MW. We have received QF status designation from FERC for our Texas windparks.

        While each of the Initial New York Windparks has filed a self-certification with the FERC that it is an EWG, there is no guarantee that regulatory or other changes will not result in the loss of such EWG status or prevent our other windparks from obtaining such status, in which case we may become subject to regulation under PUHCA.

        We also face regulatory risk imposed by various transmission providers and operators, including RTOs and ISOs, and their corresponding market rules. Transmission providers have FERC-approved tariffs that govern access to their transmission systems. These tariffs may contain provisions that limit access to the transmission grid or allocate scarce transmission capacity in a particular manner.

        To conduct our business, we must obtain licenses, permits and approvals for our windparks. These licenses, permits and approvals can be in addition to any required environmental permits. No assurance can be provided that we will be able to obtain and comply with all necessary licenses, permits and approvals for our windparks. If we cannot comply with all applicable regulations, our business, results of operations and financial condition could be adversely affected.

        We cannot predict whether federal or state governmental entities or regulatory authorities will adopt new laws or regulations, or modify existing ones, affecting the electric power industry in general, or our windparks in particular, and we cannot provide assurance that the introductions of new laws and regulations, or other future regulatory developments, will not have a material adverse impact on our business, results of operations or financial condition.

        Regulatory changes in a jurisdiction where we are developing a project may make the continued development of the project infeasible or economically disadvantageous and any expenditures we have made to date on such project may be wholly or partially written off. Any of these changes could significantly increase the regulatory-related compliance and other expenses incurred by the projects and could significantly reduce or entirely eliminate any potential revenues that can be generated by one or more of the projects, which could materially and adversely affect our business, results of operations and financial condition.

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As a result of our operating as a public company, our management will be required to devote substantial time to new compliance initiatives, which may divert management's attention from the growth and operation of our business.

        The Sarbanes-Oxley Act of 2002 and the rules subsequently implemented by the SEC and The NASDAQ Stock Market impose a number of requirements on public companies, including provisions regarding corporate governance practices. Our management and other personnel will need to devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations will make some activities more time-consuming and costly. For example, we expect these rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantial additional costs to maintain the same or similar coverage. These rules and regulations could also make it more difficult for us to attract and retain qualified persons to serve on our board of directors, our board committees or as executive officers.

        In addition, the Sarbanes-Oxley Act requires, among other things, that we maintain effective internal control over financial reporting and disclosure controls and procedures. In particular, we will need to perform system and process evaluation and testing of our internal control over financial reporting to allow management and our independent registered public accounting firm to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. Our testing, or the subsequent testing by our independent registered public accounting firm, may reveal deficiencies in our internal control over financial reporting that are deemed to be material weaknesses. Our compliance with Section 404 will require that we expend significant management time on compliance-related issues. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if we or our independent registered public accounting firm identify deficiencies in our internal control over financial reporting that are deemed to be material weaknesses, the market price of our common stock could decline and we could be subject to sanctions or investigations by The NASDAQ Stock Market, the SEC or other regulatory authorities, which would require additional financial and management resources.

Risks Relating to this Offering

Conflicts of interest may arise because some of our directors are principals of our sponsors.

        Immediately following this offering, the sponsors will hold, in the aggregate,      % of our common stock (      % if the underwriters exercise their option to purchase additional shares in full). Because of these holdings, the sponsors (subject to regulatory approval in the case of CPPIB) will be able to exercise control over all matters requiring stockholder approval, including the election of directors, amendment of our certificate of incorporation and approval of significant corporate transactions, and they will have significant control over our management and policies. The directors elected by the sponsors will also be able to control decisions affecting our capital structure.

        In addition, we intend to avail ourselves of the "controlled company" exception under The NASDAQ Stock Market rules, which eliminates the requirement that we have a majority of independent directors on our board of directors and that we have compensation and nominating committees composed entirely of independent directors, but retains the requirement that we have an audit committee composed entirely of independent directors. Our governance agreements will provide that, initially,           persons designated by JPMP and, subject to regulatory approval,            persons designated by CPPIB will serve on our board of directors following the completion of this offering. JPMP shall have the right to designate          additional persons to serve on our board of directors as additional independent directors are added to our board of directors so long as JPMP maintains certain ownership levels and we continue to be permitted to avail ourselves of the "controlled company" exception permitted under The NASDAQ Stock Market rules. Additionally, our governance agreements

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provide that directors shall be elected by a plurality of votes and do not provide for cumulative voting rights. Because of the significant common stock ownership of the sponsors, and because our board of directors will be divided into three staggered classes, the sponsors may be able to influence or control our affairs and policies even after they cease to have a right to designate a majority of the non-disinterested directors. The directors elected by the sponsors will have the authority, subject to the terms of our debt, to issue additional stock, implement stock repurchase programs, declare dividends, pay advisory fees and make other decisions, and they may have an interest in our doing so.

        The sponsors and their affiliates may invest in entities that directly or indirectly compete with us or companies in which they currently invest may begin competing with us. As a result of these relationships, when conflicts between the interests of either of the sponsors and the interests of our other stockholders arise, the sponsor-designated directors may have conflicts of interest. Although our directors and officers will have a duty of loyalty to us under Delaware law and our certificate of incorporation that will be adopted in connection with this offering, transactions that we enter into in which a director or officer has a conflict of interest are generally permissible, if done in compliance with Delaware law and our governance agreements.

        The actions of our controlling stockholders may have the effect of delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in their best interest.

There has been no prior market for our common stock and an active trading market may not develop.

        Prior to this offering, there has been no public market for our common stock. An active trading market may not develop following the closing of this offering or, if developed, may not be sustained.

        The lack of an active market may impair your ability to sell your shares of common stock at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the market value and increase the volatility of your shares of common stock. An inactive market may also impair our ability to raise capital by selling shares of common stock and may impair our ability to acquire other companies or assets by using shares of our common stock as consideration.

The price of our common stock may fluctuate substantially and your investment may decline in value.

        The initial public offering price for the shares of our common stock to be sold in this offering was determined by negotiation between the representatives of the underwriters and us. This price may not reflect the market price of our common stock following this offering. In addition, the market price of our common stock is likely to be highly volatile and may fluctuate substantially due to many factors, including:

    actual or anticipated fluctuations in our results of operations;

    failure to meet our earnings estimates;

    failure to develop and construct planned windparks on time and on budget;

    conditions and trends in the energy, capacity and REC markets in which we operate and changes in the estimation of the size and growth rate of these markets;

    availability of equipment, labor and other items required for the development and construction of a windpark;

    changes or proposed changes in, or differing interpretations of, laws or regulations affecting our business, or enforcement of these laws and regulations, or announcements relating to these matters;

    additions or departures of members of our senior management or other key personnel;

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    announcements of significant contracts or development by us or our competitors;

    loss of one or more of our significant revenue sources;

    changes in market valuation or earnings of our competitors;

    the trading volume of our common stock; and

    general market and economic conditions.

        In addition, the stock market in general, and The NASDAQ Global Market, as well as the market for broader energy and renewable energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially and adversely affect the market price of our common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company's securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us, could result in substantial costs and a diversion of management's attention and resources, which could materially harm our business, results of operations, financial condition and cash flow.

Our management team may invest or spend the net proceeds of this offering in ways with which you may not agree or in ways that may not yield a positive return.

        Presently, we anticipate using the net proceeds to us from this offering for general corporate purposes, including funding the costs of our corporate, operating and project development activities, the investment of equity into project companies and the funding of other capital expenditures, including under turbine supply agreements. Accordingly, our management will have considerable discretion in the application of these proceeds, and you will not have the opportunity to assess whether these proceeds are being used appropriately. These proceeds may be used for corporate purposes that do not increase our operating results or market value. Until the net proceeds are used, we will invest them in investment grade, short-term interest bearing marketable securities.

Future sales of our common stock may depress our share price.

        After this offering, we will have             shares of common stock outstanding. The             shares sold in this offering (or              shares if the underwriters exercise their option to purchase additional shares of our common stock from us in full) will be freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates. The remaining shares of common stock outstanding after this offering are subject to lock-up agreements, will be available for sale in the public market beginning 180 days after the date of this prospectus, and will be subject to certain volume limitations under Rule 144 of the Securities Act of 1933, as amended. The representatives of the underwriters may waive the lock-up provisions in their sole discretion. In addition, the sponsors and other significant stockholders will have certain demand and "piggy-back" registration rights with respect to the common stock that they will retain following this offering.

        Sales of substantial amounts of our common stock in the public market following this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline.

This offering will cause substantial dilution in the net tangible book value of your shares of common stock.

        If you purchase shares of our common stock in this offering, you will experience immediate dilution of $            per share based on the mid-point of the range on the cover page of this prospectus because the price that you pay will be substantially greater than the adjusted pro forma net tangible book value per share of common stock that you acquire. This dilution is due in large part to the fact

31



that our sponsors and certain members of management paid substantially less per share of common stock (after giving effect to the conversion of their equity interests into our common stock at the consummation of this offering) than the price per share to the public in this offering. If outstanding options to purchase our common stock are exercised, you will experience additional dilution. See the section entitled "Dilution" in this prospectus for a more detailed description of this dilution.

Provisions in our charter documents and Delaware law may delay or prevent acquisition of us, which could adversely affect the value of our common stock.

        Provisions contained in our certificate of incorporation and bylaws, as well as provisions of the Delaware General Corporation Law, could delay or make it more difficult to remove incumbent directors or for a third party to acquire us, even if a takeover would benefit our stockholders. These provisions include:

    a classified board of directors;

    limitations on the removal of directors;

    the power of the board of directors or the sponsors, in the case of a vacancy of a sponsor board designee, to fill any vacancy on the board of directors, whether such vacancy occurs as a result of an increase in the number of directors or otherwise;

    the ability of our board of directors to designate one or more series of preferred stock and issue shares of preferred stock without stockholder approval;

    the inability of stockholders to fix the number of directors;

    the inability of stockholders to act by written consent if less than a majority of our outstanding common stock is owned by the sponsors; and

    the inability of stockholders to call special meetings.

        Our issuance of shares of preferred stock could delay or prevent a change of control of our company. Our board of directors has the authority to cause us to issue, without any further vote or action by the stockholders, up to             shares of preferred stock, par value $                per share, in one or more series, to designate the number of shares constituting any series, and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. The issuance of shares of preferred stock may have the effect of delaying, deferring or preventing a change in control of our company without further action by the stockholders, even where stockholders are offered a premium for their shares.

        Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Although we believe these provisions provide for an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our board of directors, these provisions apply even if the offer may be considered beneficial by some stockholders.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

        Some of the statements made in this prospectus are forward-looking statements. These forward looking statements are based upon our current expectations and projections about future events. When used in this prospectus, the words "believe," "anticipate," "intend," "estimate," "expect," "should," "may" and similar expressions, or the negative of such words and expressions, are intended to identify forward- looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this prospectus are primarily located in the material set forth under the headings "Prospectus Summary," "Risk Factors," "Capitalization," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business," but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management's current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this prospectus completely and with the understanding that actual future results may be materially different from what we expect. We will not update forward-looking statements even though our situation may change in the future.

        Specific factors that might cause actual results to differ from our expectations or may affect the value of our common stock include, but are not limited to:

    significant considerations and risks discussed in this prospectus;

    operating risks and the amounts and timing of revenues and expenses;

    interruptions or failures in the transmission networks that we use;

    delays, cancellations or cost overruns involving the development or construction of our windparks;

    financial market conditions and the results of financing efforts;

    our dependence on federal tax benefits and state regulatory benefits for renewable energy generation, which may expire or may be modified in a manner that reduces available benefits;

    political, legal, regulatory, governmental, administrative and economic conditions and developments in the U.S.;

    environmental constraints on operations and environmental liabilities arising out of past or present operations;

    the effectiveness of our commodity hedges and the creditworthiness of our commodity hedge counterparties;

    the vulnerability of our windparks to adverse meteorological and atmospheric conditions;

    the impact of recent and future federal and state regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and incentives for the production of renewable energy, changes in environmental and other laws and regulations to which we are subject, as well as changes in the application of existing laws and regulations;

    current and future litigation;

    competition from other similar renewable energy projects, including any such new renewable energy projects developed in the future, and from alternative electricity producing technologies;

    the effect of and changes in economic conditions in the areas in which we operate;

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    market or business conditions and fluctuations in demand for and price of energy, capacity or RECs in the markets in which we operate; and

    the direct or indirect impact on our business resulting from terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance.


INDUSTRY AND MARKET DATA

        Unless otherwise indicated, information contained in this prospectus concerning the wind energy industry and our general expectations concerning this industry are based on information from independent industry analysts and publications and management estimates. We have derived management estimates from publicly available information as well as data from our internal research. None of the independent industry publications used in this prospectus was prepared on our or our affiliates' behalf. Estimates of historical growth rates in the markets in which we operate are not necessarily indicative of future growth rates in such markets. We have included a glossary of selected industry terms on page 147.


CORPORATE REORGANIZATION

        We are currently a Delaware limited liability company. In connection with this offering, we will convert into a Delaware corporation. This conversion has been authorized by our board of managers pursuant to the authority granted to them in our operating agreement, without any further action, including any vote or consent, required or anticipated on the part of our existing preferred or common unitholders. Upon the effectiveness of our corporate reorganization, each outstanding preferred unit and common unit will be automatically converted into a number of shares of common stock equal to the cash proceeds that are assumed to be received by such preferred or common unitholders in a distribution according to the relative rights and preferences as set forth in the operating agreement divided by an assumed initial public offering price of $                per share, the midpoint of the range set forth on the cover of this prospectus. Our corporate reorganization will be effective prior to the completion of this offering.

        After the conversion but prior to the completion of this offering, our preferred unitholders will hold      % of our outstanding common stock and our common unitholders will hold      % of our outstanding common stock.

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USE OF PROCEEDS

        Based upon an assumed initial public offering price of $            per share (the mid-point of the range set forth on the cover page of this prospectus), we estimate that our net proceeds from the sale of             shares of our common stock in this offering, after deducting underwriting discounts and commissions and estimated offering costs of approximately $                 million payable by us, will be approximately $                 million (or $                 million if the underwriters exercise their option to purchase additional shares of our common stock in full).

        We expect to use the net proceeds from this offering for general corporate purposes, including funding the costs of our corporate, operating and project development activities, the investment of equity into project companies and the funding of other capital expenditures, including under turbine supply agreements.

        The amount and timing of these expenditures will depend upon numerous factors, including the federal, state and local permitting process, the construction schedule of our projects and contractors, the delivery of goods and equipment by our suppliers and various other considerations typically associated with large-scale construction projects. Pending their use, we will invest the net proceeds of the offering in investment grade, short-term, interest-bearing, marketable securities.

        A $1.00 increase or decrease in the assumed initial public offering price of $            would increase or decrease net proceeds to us from this offering by approximately $             million after deducting underwriting discounts and commissions and estimated offering expenses. We may also increase or decrease the number of shares we are offering. Each increase of 1.0 million shares in the number of shares offered by us, together with a concomitant $1.00 increase in the assumed public offering price of $            per share, would increase the net proceeds to us from this offering by approximately $             million. Similarly, each decrease of 1.0 million shares in the number of shares offered by us, together with a concomitant $1.00 decrease in the assumed public offering price of $            per share, would decrease the net proceeds to us from this offering by approximately $             million. We do not expect that a change in the offering price or the number of shares by these amounts would have a material effect on our use of proceeds from this offering.

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DIVIDEND POLICY

        We have never declared or paid dividends on shares of our common stock or made cash distributions in respect of our common and preferred units. We expect to retain any future earnings to finance the development and growth of our business. Therefore, we do not anticipate paying any cash dividends on shares of our common stock in the foreseeable future.

        Our future decisions regarding the payment of dividends on shares of our common stock will depend on our results of operations, our financial condition and our development plans, as well as any other factors that our board of directors, in its sole discretion, may consider relevant. In addition, the terms of our existing indebtedness restrict, and our future indebtedness may restrict, our ability to pay dividends.

36



CAPITALIZATION

        The following table sets forth our consolidated cash and cash equivalents and our consolidated capitalization as of December 31, 2007:

    on an actual basis;

    on a pro forma basis to reflect our corporate reorganization, including the filing of our certificate of incorporation to authorize                  shares of common stock and                  shares of undesignated preferred stock and the automatic conversion of all our outstanding preferred and common units into                  shares of common stock as described under "Corporate Reorganization"; and

    on a pro forma as adjusted basis to reflect the sale by us of                  shares of common stock in this offering at an assumed initial offering price of $           per share, the midpoint of the range on the cover of this prospectus, after deducting underwriting discounts and commissions and estimated expenses.

        You should read this table in conjunction with our consolidated financial statements and the related notes, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Use of Proceeds" included elsewhere in this prospectus.

 
  As of December 31, 2007
 
  Actual
  Pro Forma
  Pro Forma
As Adjusted(1)

 
  (in thousands)

Total debt   $ 899,070   $     $  
Members'/stockholders' equity:                  
  Preferred units, 3,024,761 issued and outstanding, actual; no preferred units issued and outstanding, pro forma and pro forma as adjusted     302,476            
  Common units, 46,326 issued and outstanding, actual; no common units issued and outstanding, pro forma and pro forma as adjusted     46            
  Undesignated preferred stock, $           par value, no shares authorized, issued and outstanding, actual;                   shares authorized, pro forma and pro forma as adjusted; no shares issued and outstanding for all periods presented                
  Common stock, $0.01 par value, no shares authorized, issued and outstanding, actual; shares authorized, pro forma and pro forma as adjusted;                   and                   shares issued and outstanding, pro forma and pro forma as adjusted, respectively                
  Additional paid-in capital                
  Accumulated deficit     (72,009 )          
  Accumulated other comprehensive loss     (5,737 )          
   
 
 
    Total members'/stockholders' equity     224,776            
   
 
 
    Total capitalization   $ 1,123,846   $     $  
   
 
 

(1)
Each $1.00 increase (decrease) in the assumed public offering price of $             per share would increase (decrease) each of additional paid-in capital, total stockholders' equity and total capitalization by approximately $         million, assuming that the number of shares offered by us, as

37


    set forth on the cover page of this prospectus, remains the same, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase of 1.0 million shares in the number of shares offered by us, together with a concomitant $1.00 increase in the assumed offering price of $          per share, would increase each of additional paid-in capital, total stockholders' equity and total capitalization by approximately $             million. Similarly, each decrease of 1.0 million shares in the number of shares offered by us, together with a concomitant $1.00 decrease in the assumed offering price of $             per share, would decrease each of additional paid-in capital, total stockholders' equity and total capitalization by approximately $           million. The as adjusted information discussed above is illustrative only and will adjust based on the actual public offering price and other terms of this offering determined at pricing.

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DILUTION

        If you invest in our common stock in this offering, you will experience dilution to the extent of the difference between the public offering price per share you pay in this offering and the pro forma net tangible book value or deficit per share of our common stock after this offering. Net tangible book value per share is determined at any date by subtracting our total liabilities from the total book value of our tangible assets and dividing the difference by the number of shares of common stock deemed to be outstanding at that date. Our pro forma net tangible book value as of December 31, 2007, was $         million, or $          per share, based on the number of shares of common stock outstanding as of December 31, 2007 after giving effect to our corporate reorganization.

        After giving effect to the sale of common stock offered in this offering at an assumed initial public offering price of $            per share, after deducting underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma as adjusted net tangible book value as of December 31, 2007 would have been approximately $             million, or approximately $            per share of common stock. This represents an immediate increase in pro forma as adjusted net tangible book value of $ per share to existing stockholders, and an immediate dilution of $            per share to investors purchasing shares of common stock in this offering. The following table illustrates this substantial and immediate per share dilution to new investors:

Assumed initial public offering price per share         $  
  Pro forma net tangible book value per share as of December 31, 2007   $        
  Increase in pro forma net tangible book value per share to existing stockholders attributable to investors in this offering            
   
     
Pro forma as adjusted net tangible book value per share after this offering            
         
Pro forma dilution per share to new investors         $  
         

        Each $1.00 increase or decrease in the assumed public offering price of $            per share would increase or decrease our pro forma as adjusted net tangible book value by approximately $             million, or approximately $             per share, and the pro forma dilution per share to investors in this offering by approximately $             per share, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. An increase of 1.0 million shares in the number of shares offered by us, together with a concomitant $1.00 increase in the assumed offering price of $            per share, would result in a pro forma as adjusted net tangible book value of approximately $             million, or $            per share, and the pro forma dilution per share to investors in this offering would be $            per share. Similarly, a decrease of 1.0 million shares in the number of shares offered by us, together with a concomitant $1.00 decrease in the assumed public offering price of $            per share, would result in an pro forma as adjusted net tangible book value of approximately $             million, or $            per share, and the pro forma dilution per share to investors in this offering would be $            per share. The pro forma as adjusted information discussed above is illustrative only and will adjust based on the actual public offering price and other terms of this offering determined at pricing.

        If the underwriters exercise in full their option to purchase additional shares of common stock in this offering, the pro forma as adjusted net tangible book value per share after the offering would be $            per share, the increase in the pro forma net tangible book value per share to existing

39



stockholders would be $            per share and the pro forma dilution to new investors purchasing common stock in this offering would be $            per share.

Differences Between New and Existing Investors in Number of Shares and Amount Paid

        The following table summarizes, as of December 31, 2007, on a pro forma basis after giving effect to our corporate reorganization the differences between the number of shares of common stock purchased from us, the total consideration and the weighted average price per share paid by existing stockholders and by investors participating in this offering at an assumed initial public offering price of $            per share, before deducting underwriting discounts and commissions and estimated offering expenses:

 
  Shares purchased
  Total consideration
   
 
  Average
price per
share

 
  Number
  Percent
  Amount
  Percent
Existing stockholders         % $       % $  
Investors in the offering         % $       % $  
   
 
 
 
 
  Total       100 % $     100 % $  
   
 
 
 
 

        The number of shares of common stock outstanding in the table above is based on the pro forma number of shares outstanding as of December 31, 2007 and assumes no exercise of the underwriters' over-allotment option. If the underwriters' over-allotment option is exercised in full, the number of shares of common stock held by existing stockholders will be reduced to            % of the total number of shares of common stock to be outstanding after this offering, and the number of shares of common stock held by investors participating in this offering will be increased to                        shares or            % of the total number of shares of common stock to be outstanding after this offering.

        As of December 31, 2007, there were no options or warrants to purchase common stock outstanding. Effective upon the closing of this offering, an aggregate of             shares of our common stock will be reserved for future issuance under our benefit plans. To the extent that any of these options are exercised, new options are issued under our benefit plans or we issue additional shares of common stock in the future, there will be further dilution to investors participating in this offering.

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SELECTED CONSOLIDATED FINANCIAL DATA

        The following table sets forth our selected consolidated financial data for the periods ended and at the dates indicated in such table. We have derived the selected consolidated financial data as of and for the period ended December 31, 2004 from our audited consolidated financial statements that are not included in this prospectus. We have derived the selected consolidated financial data as of and for the periods ended December 31, 2007, 2006 and 2005 and for the period from August 31, 2004 (date of inception) to December 31, 2007 from our audited consolidated financial statements included elsewhere in this prospectus.

        The information set forth below should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements included elsewhere in this prospectus.

 
  Year Ended December 31,
  August 31, 2004
(date of inception)
to December 31,

 
  2007
  2006
  2005
  2004
  2007
 
  (in thousands)

Statement of operations data:                              
  Revenues   $   $   $   $   $
   
 
 
 
 
Operating expenses:                              
  Salaries, wages, employment taxes and fringe benefits     10,627     9,788     2,919     352     23,686
  Write-off of construction in progress     574     5,500             6,074
  General and administrative expenses     8,265     4,024     4,771     733     17,793
  Depreciation     776     492     83         1,351
  New project development     3,625     2,241     10         5,876
  Change in fair value of derivative contract     21,073                 21,073
  Other expense     32     18             50
   
 
 
 
 
  Operating loss     44,972     22,063     7,783     1,085     75,903
  Interest income     2,486     1,384     24         3,894
   
 
 
 
 
  Net loss   $ 42,486   $ 20,679   $ 7,759   $ 1,085   $ 72,009
   
 
 
 
 
Net loss allocable to common unitholders:                              
  Net loss     (42,486 )   (20,679 )              
  Preferred dividend(1)     18,662     4,018                
   
 
 
           
  Net loss allocable to common unitholders   $ (61,148 ) $ (24,696 ) $            
   
 
 
           
Net loss allocable to common unitholders per unit:                              
  Basic and diluted   $ (131.99 ) $ (69.49 ) $            
   
 
 
           
  Weighted average units used in the caculation of net loss per unit allocable to common unitholders basic and diluted     463,260     355,378                
   
 
 
           

(1)
The preferred dividend was not declared (or paid) during the period from August 31, 2004 (date of inception) to December 31, 2007.

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  Year Ended December 31,
  August 31, 2004
(date of inception)
to December 31,

 
 
  2007
  2006
  2005
  2004
  2007
 
 
  (in thousands)

 
Pro forma net loss data (unaudited):                                
  Net loss allocable to common unitholders as reported   $ (61,148 )                        
  Pro forma adjustment for income tax benefit                              
  Pro forma net loss allocable to common unitholders   $ (61,148 )                        
   
                         
Pro forma basic and diluted net loss allocable to common unitholders per common unit                                
   
                         
Weighted average shares used in pro forma basic and diluted net loss per common share allocable to common unitholders                                
   
                         
Statement of cash flows data:                                
  Cash flows provided (used) by operating activities   $ 39,921   $ (20,210 ) $ (6,036 ) $ (1,003 ) $ 12,672  
  Cash flows used by investing activities     (617,867 )   (507,141 )   (47,206 )       (1,172,214 )
  Cash flows provided by financing activities     618,043     532,591     54,375     1,359     1,206,368  

Balance sheet data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Cash and cash equivalents   $ 46,826   $ 6,729   $ 1,489   $ 356        
  Restricted cash     50,401     12,995                
  Prepaid and other current assets     63,507     1,925                
  Construction in progress     959,202     442,435     13,387            
  Property and equipment, net     4,653     3,105     1,409            
  Construction material deposits     150,259     153,493     36,660            
  Deferred financing costs     15,087     2,251                    
  Other assets     1,208     559     250            
   
 
 
 
       
  Total assets   $ 1,291,143   $ 623,492   $ 53,195   $ 356        
   
 
 
 
       
 
Short-term liabilities

 

$

135,099

 

$

478,755

 

$

46,619

 

$

82

 

 

 

 
  Long-term liabilities     931,268                    
   
 
 
 
       
  Total liabilities     1,066,367     478,755     46,619     82        
 
Members equity

 

 

224,776

 

 

144,737

 

 

6,576

 

 

274

 

 

 

 
   
 
 
 
       
  Total liabilities and equity   $ 1,291,143   $ 623,492   $ 53,195   $ 356        
   
 
 
 
       

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        You should read the following discussion and analysis of our results of operations, financial condition and liquidity in conjunction with our consolidated financial statements and the related notes. Some of the information contained in this discussion and analysis or set forth elsewhere in this prospectus, including information with respect to our plans and strategies for our business, statements regarding the industry outlook, our expectations regarding the future performance of our business, and the other non-historical statements contained herein are forward-looking statements. See "Special Note Regarding Forward-Looking Statements." You should also review the "Risk Factors" section of this prospectus for a discussion of important factors that could cause actual results to differ materially from the results described herein or implied by such forward-looking statements.

Overview

        We are a rapidly growing wind energy company operating 282 MW of electrical generating capacity with more than 950 MW of additional capacity that we expect to commence operations during 2008 and 2009. We are focused on developing, financing, constructing, owning and operating windparks in attractive energy markets in the United States. Our strategy is to grow our fully integrated business principally through organic development in regions with deregulated energy markets, acceptable wind resources and favorable legislative and economic incentives such as RPS programs and active REC markets.

Recent Developments

        In March 2008, we commenced operation of our Bliss and Ellenburg windparks. In April 2008, we commenced operation of our Clinton windpark. All three of these windparks are located in New York, and we refer to them as our Initial New York Windparks. We expect that these windparks will collectively provide 282 MW of capacity. We will sell the energy generated by, and capacity of, these windparks to the New York Independent System Operator, or NYISO, the entity that oversees the wholesale electricity markets in the state of New York. In order to limit our exposure to volatility in NYISO energy trading prices, we have entered into a hedging arrangement with Credit Suisse with respect to a substantial portion of the energy we generate at these windparks. We have also agreed to sell the majority of the RECs generated through the operation of these windparks to New York State Energy Research and Development Authority, or NYSERDA, the entity that administers the central procurement of RECs for the State of New York.

        On April 8, 2008 we entered into a mandate letter with a group of financial institutions, under which the financial institutions agreed to provide construction and term loans, letter of credit facilities and tax equity financing for our Great Plains I windpark that is currently in construction in Texas. The financial institutions' commitment under the mandate letter is subject to the completion of definitive agreements and customary conditions precedent.

        In connection with our continual assessment of our capital and resource allocation, we determined that it was strategically appropriate to sell two windparks that were in development in Michigan. On February 29, 2008, our subsidiary, Noble Thumb Windpark, LLC, entered into an agreement with Babcock & Brown Renewable Holdings Inc. for the sale of the wind power development assets associated with our projects in Huron and Sanilac Counties, Michigan as well as 46 wind turbines intended for use in the Huron County project. The sale price is approximately $85.1 million and we have scheduled a tentative closing in May 2008. The sale price is subject to certain adjustments; however, we believe that the sale price, less selling expenses, will exceed the carrying amount of the assets group held for sale. Accordingly, we do not expect to recognize a loss in connection with this transaction.

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Revenues

        We expect to generate revenues from the sale of energy and capacity from our operating windparks as well as from the sale of RECs attributable to such operations. Our revenues from the Initial New York Windparks will consist of:

    Sale of Energy.  We will sell the energy that we produce at the Initial New York Windparks into NYISO at the market clearing price on an hourly basis. The market clearing price will be determined by supply and demand in the NYISO market at any given time at the point of sale and is largely tied to the marginal cost of production of the conventional power generators.

    Sale of RECs.  We have agreed to sell the majority of the RECs we expect to generate at our Initial New York Windparks to NYSERDA pursuant to executed standard form long-term, fixed-price contracts. One REC is created for each MWh of energy we produce. However, the total amount of RECs we can sell under the NYSERDA contracts with respect to all three Initial New York Windparks is limited to 850,000 per contract year. Consequently, to the extent that we create an amount of RECs that exceed that number in any contract year, we intend to sell the excess RECs on the open market.

    Sale of Capacity.  We expect to receive monthly payments for the installed capacity, or ICAP, at our Initial New York Windparks. These payments will be determined by a formula based on a fixed percentage of the ICAP of the Initial New York Windparks multiplied by a fluctuating price, referred to as the ICAP price. We have not yet entered into any agreements for the sale of ICAP, however, we may sell the ICAP either directly to NYISO or to third-party market participants. Prices for the sale of the ICAP will be made at auction clearing prices if sold through NYISO, or at negotiated market prices at the time of any sale if sold to third-party market participants. In markets where our windparks qualify to receive capacity payments, generally only a portion of the windpark's capacity is eligible to receive capacity payments. This portion is typically based on the previous year's average net capacity factor during peak periods.

        In order to limit our exposure to price volatility in the NYISO energy market, our subsidiary, Noble Environmental Power 2006 Hold Co, LLC, or NEP NY 2006, entered into a ten-year energy hedging arrangement with Credit Suisse. Under this financial fixed-for-float energy swap arrangement:

    we pay Credit Suisse a monthly amount equal to the product of (i) the prevailing market price for energy that we sell in that month, and (ii) the actual amount of energy that we generated during such month up to a specified cap; and

    Credit Suisse pays us a monthly amount equal to the product of (i) a specified fixed price, and (ii) the actual amount of energy that we generated during such month up to the same specified cap.

        Pursuant to this agreement, we have implemented a tracking account that tracks, on a monthly basis, the difference between our energy production from the Initial New York Windparks and a predetermined notional volume under the swap for that month. Our monthly net settlement payments with Credit Suisse may be more or less than would otherwise be due based on the notional volume of the swap. This tracking account was incorporated into the hedge in order to allow us to manage our risk associated with the inherent volatility associated with the volume of energy production from our windparks. In addition, (i) in certain circumstances where our energy production levels and the price of energy sold into the NYISO generate excess cash flow, we are required to make cash payments to Credit Suisse in addition to those described above, which are credited in our favor in the tracking account, and (ii) in certain circumstances where our energy production levels and the price of energy sold into the NYISO are below specified amounts, and if certain thresholds are met, Credit Suisse is required to make monthly cash payments to us, which have no impact on the tracking account. The tracking account is designed to capture the net amounts, if any, of over or under-payment between the

44


parties over the life of the agreement and is settled at the end of the ten-year term of the hedging arrangement. We have the option to repay any amounts due from us to Credit Suisse over a two year period following the end of the hedging arrangement, subject to certain conditions, including the requirement that we provide additional collateral to Credit Suisse.

        We anticipate that in future projects we will generate revenue in a similar fashion, including from the sale of energy and RECs and, if a capacity market exists in the relevant jurisdiction, from the sale of capacity. We also expect to enter into energy hedges with respect to our future projects similar to our current energy hedge arrangement with Credit Suisse.

Expenses

        Our principal expenses include those associated with our corporate- and project-level operations and new project development efforts.

        Our corporate operating expenses include salaries and wages, employee taxes and fringe benefits and general and administrative expenses, including payments for legal, accounting and other professional services.

        Our project-level expenses include labor costs, easement payments to our landowners, interest expenses and associated financing costs, insurance and costs to maintain permits, payments under local taxing authority agreements, payments under agreements with local governments and municipalities, the cost for spare parts for wind turbines and other turbine-maintenance expenses, and expenses for legal, engineering and other professional services.

        New project development expenses include expenses relating to initial project development activities, including labor costs, expenses related to our feasibility analyses and other studies, payments for legal and other professional and advisory services, and easement payments made before a project becomes financially viable and capitalized.

        Certain of these expenses may be capitalized depending on the stage of development of a particular windpark based on our estimates and judgments involving the completion of certain milestones. A discussion of these determinations and the capitalization of such expenses is included under the caption "—Critical Accounting Policies—Capitalization and Investment in Project Assets."

        During recent periods, we have seen increases in the costs relating to key aspects of our windpark development, financing, construction and operations activities. These include increases in:

    the prices we must pay to landowners for access to land with attractive wind resources;

    the interest rates, target yields and fees we may have to pay in connection with the debt and tax equity financing structures that we use;

    the price of wind turbine generators and transportation costs;

    the cost of construction due to increased labor and subcontracting costs and increases in the prices of certain construction equipment that we rely on for turbine erection; and

    the amounts we must pay in order to attract and retain talented development, project financing, meteorological, construction and operations professionals.

We believe that the costs for some or all of these items are likely to continue to increase in future periods and therefore could negatively impact our results of operations.

Critical Accounting Policies

        The consolidated financial statements included within this prospectus have been prepared in accordance with generally accepted accounting principles in the U.S., or GAAP. Our critical accounting

45



policies are more fully described in Note 1 to our audited consolidated financial statements, which are included elsewhere in this prospectus. However, certain of our accounting policies are particularly important to an understanding of our financial position and results of operations. In applying these critical accounting policies, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. Such estimates are based on management's historical experience, the terms of existing contracts, management's observance of trends in the wind energy industry, information provided by our suppliers and counterparties and information available to management from other outside sources, as appropriate.

        The accounting estimates and assumptions discussed in this section are those that involve significant judgments and the most uncertainty. Changes in these estimates or assumptions could materially affect our financial position and results of operations and are therefore important to an understanding of our consolidated financial statements.

        Capitalization and investment in project assets.    Our windparks have four basic phases: (i) development (which includes pre-development), (ii) financing and commodity risk management, (iii) engineering and construction and (iv) operation and maintenance. The development phase is further divided into pre-development and development sub-phases. During the pre-development sub-phase, milestones are created to ensure that a project is financially viable. Project viability is obtained when it becomes probable that costs incurred will generate future economic benefits sufficient to recover these costs. Examples of milestones required for a viable windpark include the following:

    the identification, selection and acquisition of sufficient land for control of the land area required for a windpark;

    the confirmation of a regional electricity market and the availability of RECs;

    the confirmation of acceptable wind resources;

    the confirmation of the potential to interconnect to the electric transmission grid;

    the determination of limited environmental sensitivity; and

    the confirmation of local community receptivity and limited potential for organized opposition.

        All project costs are expensed during the pre-development phase. Once the milestones for development are achieved, a project is moved from the pre-development phase into the development and engineering and construction phases. Costs incurred in these phases are capitalized as incurred, included within construction in progress, or CIP, and not depreciated until placed into commercial service.

        From our inception to date, interest expense and associated financing costs have been capitalized into our projects. At December 31, 2007, we had capitalized $105.5 million of these expenses and costs.

        Once a project is placed into operation, all accumulated costs will be reclassified from CIP to property and equipment, and become subject to depreciation or amortization over a 25 year estimated life.

        Valuation and recoverability of long-lived assets.    We will periodically evaluate the carrying value of property and equipment, if and when events and circumstances warrant such a review. The carrying value of property and equipment is considered impaired when its anticipated undiscounted cash flows are less than its carrying value. A loss is then recognized based on the amount by which the carrying value exceeds the fair value of the asset.

        We are in the process of making a significant investment in our windparks and we will continue to make significant investments over the next several years. We will evaluate the recoverability of these

46



assets whenever events or changes in circumstances indicate the carrying value of our assets may not be recoverable.

        We have written off certain construction in progress. Write-offs totaled $0.6 million for the year ended December 31, 2007, $5.5 million for the year ended December 31, 2006, and $6.0 million from inception through December 31, 2007. The $0.6 million write-off in 2007 consisted primarily of internal salaries and overhead, third party engineering, other professional fees and certain material costs incurred in connection with the purchase of certain project development rights from a third party. In June 2007, in connection with our continual assessment of our capital and resource allocation, we determined the project was no longer in our economic interests, and wrote off all capitalized costs.

        During 2006, we recognized a charge to operations totaling $5.5 million related to previously capitalized costs incurred in connection with the development of Noble Thumb Windpark I. Such costs consisted primarily of internal salaries and overhead, third-party engineering, mobilization and transportation costs and certain transformer and substation costs. The write-off was determined to be necessary based on changes associated with the scope and interconnection of the original project. We determined that the original project should be split into multiple projects. Accordingly, certain costs incurred for the original project could no longer be utilized and were written off. However, as discussed above, in February 2008, we agreed to sell the assets associated with this project.

        Derivative Instruments.    We enter into various derivative transactions in order to hedge our exposure to certain market risks. We primarily use derivatives to manage our interest rate and commodity exposures. We do not enter into derivative transactions for trading purposes.

        Under Statement of Financial Accounting Standards, or SFAS, No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, we recognize all derivatives as either assets or liabilities in our balance sheet and measure those instruments at fair value. Changes in fair value of derivatives are recognized in earnings unless specific hedge criteria are met as discussed below. Income and expense related to derivative instruments are recorded in the same category as generated by the underlying asset or liability.

        SFAS 133 enables companies to designate qualifying derivatives as hedging instruments based on the exposure being hedged. These hedge designations include fair value hedges and cash flow hedges. Changes in the fair value of a derivative that is highly effective, and is designated and qualifies as a fair value hedge, are recognized in earnings as offsets to the changes in the fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective, and is designated and qualifies as a cash flow hedge, are deferred in accumulated other comprehensive income/loss and are reclassified into income as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. For all hedge contracts, at inception we prepare formal documentation of the hedge and effectiveness testing in accordance with SFAS No. 133. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

        The application of SFAS 133 is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, determination of the fair value of derivatives, identification of hedge relationships, assessment and measurement of hedge ineffectiveness and election and designation of the normal purchases and sales exception. All of these judgments, depending upon their timing and effect, can have a significant impact on our consolidated operations.

        For cash flow hedges of forecasted transactions, we estimate the future cash flows represented by the forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing for the reclassification of gains or losses on cash flow hedges from accumulated other comprehensive income/loss into earnings.

47


        In the event the forecasted transaction to which a cash flow hedge relates is no longer probable, the amount in other accumulated comprehensive income/loss is recognized in earnings and generally the hedge relationship is terminated. Gains resulting from the early termination of interest rate swap agreements are deferred and amortized as adjustments to interest expense over the remaining maturity of the debt originally covered by the terminated swap.

        Accounting for Income Taxes.    We utilize the asset and liability method of accounting for deferred income taxes as prescribed by the SFAS 109 "Accounting for Income Taxes." This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the tax return and financial statement reporting bases of certain assets and liabilities. In June 2006, the Financial Accounting Standards Board, or the FASB, issued Interpretation No. 48 ("FIN 48"), "Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109)," which is effective for fiscal years beginning after December 15, 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We adopted FIN 48 as of January 1, 2007. The adoption had no impact on our consolidated financial statements.

        Asset Retirement Obligations.    We account for asset retirement obligations and conditional assets retirement obligations under SFAS No. 143, "Accounting for Asset Retirement Obligations," and FIN 47, "Accounting for Conditional Assets Retirement Obligations." SFAS 143 and FIN 47 require that a liability for the fair value of an asset retirement obligation (which represents the cost for removal of turbines and related equipment and remediation of the land) be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as part of the carrying amount of the long-lived asset. The asset retirement cost is subsequently amortized on a straight-line basis over a 25-year estimated useful life. Changes in the asset retirement obligation resulting from the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense, which is included in depreciation and amortization expense in the consolidated statements of operations. Changes resulting from revisions to the timing or amount of the original estimates of cash flows are recognized as an increase or a decrease in the asset retirement cost and asset retirement obligation.

Recent Accounting Pronouncements

        In March 2008, the FASB issued SFAS 161, "Disclosures about Derivative Instruments and Hedging Activities," which expands derivative disclosure by requiring an entity to disclose: (i) an understanding of how and why an entity uses derivatives; (ii) an understanding of how derivatives and related hedged items are accounted for; and (iii) transparency into the overall impact of derivatives on an entity's financial position, results of operations, and cash flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008. Earlier adoption is encouraged. We are currently analyzing the requirements of SFAS 161 and will adopt the standard on January 1, 2009.

        In December 2007, the FASB issued SFAS 160, "Noncontrolling Interests in Consolidated Financial Statements," which significantly changes the financial reporting relationship between a parent and non-controlling interests (i.e. minority interests). SFAS 160 requires all entities to report minority interests in subsidiaries as a separate component of equity in the consolidated financial statements. Accordingly, the amount of net income attributable to the non-controlling interest is required to be included in consolidated net income on the face of the income statement. Further, SFAS 160 requires that the transactions between a parent and non-controlling interests should be treated as equity. However, if a subsidiary is deconsolidated, a parent is required to recognize a gain or loss. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. Earlier adoption is prohibited. SFAS 160 will be applied prospectively, except for presentation and disclosure requirements which are

48



required to be applied retrospectively. We will adopt SFAS 160 effective January 1, 2009. We do not expect the adoption of SFAS 160 to have a material impact on our consolidated financial statements.

        In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities." SFAS 159 permits, but does not require, entities to account for financial instruments at fair value. The standard does not extend to non-financial instruments. We have elected not to adopt the fair value provisions of SFAS 159.

        In September 2006, the FASB, issued SFAS No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value and is required to be implemented in the first quarter of 2008. SFAS 157 provides a fair value hierarchy, giving the highest priority to quoted prices in active markets, and is expected to be applied to fair value measurements of derivative contracts that are subject to mark-to-market accounting and other assets and liabilities reported at fair value. In most cases, SFAS 157 is required to be implemented prospectively with adjustments to fair value reflected as a cumulative effect adjustment to the opening balance of members' equity as of January 1, 2008.

        Effective January 1, 2008, we adopted SFAS 157 except for non-financial assets and liabilities. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity's own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:

        Level 1—measurements utilize unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access. These consist primarily of listed equity securities, exchange traded derivatives and certain U.S. government treasury securities.

        Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as swaps, forward contracts or options and most fixed income securities.

        Level 3—measurements use unobservable inputs for assets or liabilities, are based on the best information available and might include an entity's own data. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of assets and liabilities valued through an internal modeling process.

        The following table presents information about our respective assets and liabilities measured at fair value on a recurring basis at December 31, 2007, including the fair value measurements and the levels

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of inputs used in determining those fair values as we would expect to report them had we adopted SFAS 157 as of December 31, 2007.

Description

  Total at
December 31,
2007

  Quoted Market
Prices for Identical
Assets (Level 1)

  Significant Other
Observable Inputs
(Level 2)

  Significant
Unobservable
Inputs
(Level 3)

 
  (in thousands)
Liabilities:                        
Derivative Contacts:                        
  Energy Hedge(1)   $ 21,073   $   $   $ 21,073
  Interest Rate Swap(2)   $ 5,737   $   $ 5,737   $

(1)
For contracts where no observable market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices.

(2)
Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.

Results of Operations

Comparison of the Year Ended December 31, 2007 and the Year Ended December 31, 2006

 
  Year Ended December 31,
   
 
 
  Period-to-
Period
Change

 
 
  2007
  2006
 
 
  (in thousands)
 
Revenues   $   $    
   
 
     
Salaries, wages, employment taxes and fringe benefits     10,627     9,788   8.6 %
Write-off of construction in progress     574     5,500   (89.6 )%
General and administrative expenses     8,265     4,024   105.4 %
Depreciation     776     492   57.7 %
New project development     3,625     2,241   61.8 %
Change in fair value of derivative contract     21,073        
Other expense     32     18   77.8 %
   
 
     
Operating loss     44,972     22,063   103.8 %
Interest income     2,486     1,384   79.6 %
   
 
     
Net loss   $ 42,486   $ 20,679   105.5 %
   
 
     

        Revenues.    We did not generate any revenues in the years ended December 31, 2007 or 2006, as none of our windparks had yet commenced operations.

        Salaries, Wages, Employment Taxes and Fringe Benefits.    Salary, wages, employment taxes and fringe benefits for the year ended December 31, 2007 were $10.6 million, as compared with $9.8 million for the year ended December 31, 2006, which represented a $0.8 million or 8.6% increase. This increase was due to an overall increase in headcount across our business to 138 at December 31, 2007 from 91 at December 31, 2006. In addition, we hired several executives during this timeframe which further increased salary and wage expense from that of prior periods.

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        Write-off of Construction In Progress.    Write-offs of construction in progress for the year ended December 31, 2007 were $0.6 million, as compared to $5.5 million for the year ended December 31, 2006, which represented a $4.9 million or 89.6% decrease. The $0.6 million write-off in 2007 related to professional, consulting and material costs incurred in connection with the purchase of certain project development rights from a third party. The $5.5 million write-off in 2006 was associated with previously capitalized costs incurred in the development of Noble Thumb Wind Park I. Based on changes associated with the scope and interconnection of the original project, we determined that we could no longer utilize certain costs incurred for the original project and wrote-off those costs.

        General and Administrative Expenses.    General and administrative expenses for the year ended December 31, 2007 were $8.3 million, as compared with $4.0 million for the year ended December 31, 2006, which represented a $4.3 million or 105.4% increase. This increase was due primarily to increases in professional fees (legal and accounting services) of approximately $2.3 million, and an increase in rent, utilities, recruiting, temporary personnel, public relations and other overhead expenses of approximately $2.0 million. The increase in professional fees related to non-capitalized legal costs incurred in connection with project organization, permitting and regulatory matters, and costs associated with professional advisory services and financing transactions. Additionally, professional fees included increased costs associated with our financial statement audit and tax compliance requirements.

        Depreciation Expense.    Depreciation expense for the year ended December 31, 2007 was $0.8 million, as compared to $0.5 million for the year ended December 31, 2006, which represented a $0.3 million or 57.7% increase. The increase was due to additions to property and equipment of $2.6 million for the year ended December 31, 2007.

        New Project Development Expenses.    New project development expenses for the year ended December 31, 2007 were $3.6 million, as compared with $2.2 million for the year ended December 31, 2006, which represented a $1.4 million or 61.8% increase. This increase was due to an increase in personnel and consultants associated with the expansion of our project development activities.

        Change in fair value of derivative contract.    We entered into a ten-year fixed-for-float energy hedging arrangement with Credit Suisse in June 2007. The change in the fair value of this derivative contract for the year ended December 31, 2007 was $21.0 million. As the wind generating assets associated with this instrument were not yet generating power at December 31, 2007, and this instrument was not designated as a hedge under SFAS 133, we recorded the decrease in the fair value as a liability and a corresponding charge to operations.

        Interest Income.    Interest income for the year ended December 31, 2007 was $2.5 million, as compared with $1.4 million for the year ended December 31, 2006, which represented a $1.1 million or 79.6% increase. This increase was due to an increase in interest earned in connection with the short-term investment of cash and restricted cash balances. Cash and restricted cash balances available for investment purposes increased to approximately $97.2 million at December 31, 2007 from $19.7 million at December 31, 2006. Interest during 2007 and 2006 was earned on our short-term investment of cash and restricted cash balances associated with capital contributions from our sponsors received during 2007 and 2006 of approximately $128.3 million and $158.5 million and proceeds from borrowings of approximately $1,015.4 million and $663.8 million, respectively.

        Net Loss.    Net loss for the year ended December 31, 2007 was $42.5 million, as compared with $20.7 million for the year ended December 31, 2006, which represented a $21.8 million or 105.5% increase. This increase was attributable to the factors discussed above.

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Comparison of the Year Ended December 31, 2006 and the Year Ended December 31, 2005

 
  Year Ended December 31,
   
 
 
  Period-to-
Period
Change

 
 
  2006
  2005
 
 
  (in thousands)

 
Revenues   $   $    
   
 
     
Salaries, wages, employment taxes and fringe benefits     9,788     2,919   235.3 %
Write-off of construction in progress     5,500        
General and administrative expenses     4,024     4,771   (15.7 )%
Depreciation     492     83   492.8 %
New project development     2,241     10   NM *
Other expense     18        
   
 
     
Operating loss     22,063     7,783   183.5 %
Interest income     1,384     24   NM *
   
 
     
Net loss   $ 20,679   $ 7,759   166.5 %
   
 
     

      *
      NM = not meaningful

        Revenues.    We did not generate any revenues in the years ended December 31, 2006 and 2005 as none of our windparks had yet commenced operations.

        Salaries, Wages, Employment Taxes and Fringe Benefits.    Salary, wages, employment taxes and fringe benefits for the year ended December 31, 2006 were $9.8 million, as compared with $2.9 million for the year ended December 31, 2005, which represented a $6.9 million or 235.3% increase. This increase was due to an overall increase in head count across our business to 91 at December 31, 2006 from 41 at December 31, 2005. In addition, we hired several executives during this timeframe which increased salary and wage expense from that of prior periods.

        Write-off of Construction in Progress.    Write-offs of construction in progress for the year ended December 31, 2006 of $5.5 million are discussed above. There were no write-offs of construction in progress during the year ended December 31, 2005.

        General and Administrative Expenses.    General and administrative expenses for the year ended December 31, 2006 were $4.0 million, as compared with $4.8 million for the year ended December 31, 2005, which represented a $0.8 million or 15.7% decrease. This decrease was due primarily to decreases in professional fees and easements costs of approximately $1.0 million and $0.5 million, respectively, offset by increases in other overhead amounts of approximately $0.7 million. The decrease in professional fees and easement costs resulted from our capitalization during 2006 of certain costs as project construction in progress rather than the expensing of such costs as had been done during 2005.

        Depreciation Expense.    Depreciation expense for the year ended December 31, 2006 was $0.5 million, as compared to $0.1 million for the year ended December 31, 2005, which represented a $0.4 million or 492.8% increase. The increase was due to additions to property and equipment of $2.4 million for the year ended December 31, 2006.

        New Project Development Expenses.    New project development expenses for the year ended December 31, 2006 were $2.2 million. There was no material new project development expenses during the year ended December 31, 2005. The expense during 2006 was due to an increase in additional personnel and consultants and feasibility analysis expenses associated with the expansion of our project development activities.

        Interest Income.    Interest income for the year ended December 31, 2006 was $1.4 million. We had no material interest income during the year ended December 31, 2005. Interest during 2006 was earned

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on our short-term investment of cash and restricted cash balances associated with capital contributions from our sponsors received during 2006 of approximately $158.5 million and proceeds from short-term borrowings of approximately $663.8 million.

        Net Loss.    Net loss for the year ended December 31, 2006 was $20.7 million, as compared with $7.8 million for the year ended December 31, 2005, which represented a $12.9 million or 166.5% increase over 2005. This increase was attributable to the factors discussed above.

Liquidity and Capital Resources

        In addition to funding our general corporate and administrative, overhead expenses and working capital needs, our principal liquidity requirements can be separated into four general categories. These include liquidity required to:

    fund the purchase of turbines for our windparks;

    fund the cost of our development efforts with respect to a particular windpark;

    prior to the commencement of operations at a particular windpark, fund windpark construction and refinance indebtedness associated with previously purchased turbines; and

    after the commencement of operations at a particular windpark, refinance indebtedness incurred in connection with the construction of that windpark and the refinancing of turbine costs.

        Our capital expenditures primarily relate to investments in property and equipment relating to the development of our windparks. We currently expect to spend approximately $4.3 billion on these items over the next three years.

        The primary working capital needs for an individual windpark include spare parts, operations and maintenance fees and real estate easement payments. The initial working capital needs for a windpark are included in the capital budget for completing construction and are financed with proceeds from the construction loan.

        We anticipate that our cash and restricted cash on hand, together with our expected cash flow from operations, borrowings under our turbine credit facilities, capital contributions from tax equity investors and current and future borrowings under project construction and term loans, will provide us with sufficient capital and liquidity to fund our liquidity requirements for the next 12 months. Additional funds may be necessary sooner than we currently anticipate in the event of changes in our development schedule, increases in our development costs, unanticipated prepayments to suppliers, cost overruns or any shortfall in our estimated levels of operating cash flow, or to meet other unanticipated expenses. While we expect that we will have access to capital from institutional investors interested in investing in our tax equity financing structures and from the commercial bank lending market for project construction loans and term loans to our project companies on a limited recourse basis, we cannot assure you that we will be able to obtain additional financing on a timely basis, on acceptable terms or at all. See "Risk Factors—Our development plan requires substantial additional capital, and we may be unable to raise financing when needed or on acceptable terms, which could force us to delay, reduce or eliminate some or all of our development plans" and "—Our use of tax equity financing structures will place certain limits on our project subsidiaries' operational flexibility and our rights to the cash flow generated by the windparks."

        A substantial portion of our subsidiaries' assets has been pledged as security for our credit facilities. These credit facilities restrict the subsidiaries' ability to pay dividends (with certain exceptions), or make loans or advances to us. See "Description of Certain Financing Arrangements" for additional information on our credit facilities.

Turbine Financing

        We fund the cash required to pay for turbines purchased under turbine supply agreements with GE with borrowings by certain of our subsidiaries under turbine credit facilities, which consist of a first

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lien revolving turbine credit facility and a second lien turbine credit facility entered into by such subsidiaries. Together, these facilities allow us to finance between 60% and 100% of our turbine purchases with debt.

        Our indirect subsidiary, NEP Equipment Finance Co., LLC, is the borrower under the first lien revolving turbine credit facility, which provides for up to $460.0 million of revolving borrowings and matures in March 2010. Borrowings under this facility currently accrue interest at a floating rate of LIBOR plus 2.75% per annum, with interest on outstanding borrowings ranging from 6.6% to 7.0% as of December 31, 2007. We are also required to pay a commitment fee, currently equal to 1.375%, on the undrawn portion of the facility. As of December 31, 2007, we had $230.1 million of indebtedness outstanding under this facility. Obligations under the first lien revolving turbine credit facility are secured by first priority liens on the assets of, and first priority pledges of all of the equity interests of, NEP Equipment Finance Co., LLC and each of our subsidiaries that are parties to the turbine supply agreements.

        Borrowings under the first lien revolving turbine credit facility are limited to the sum of (i) 80% of the contract price of the turbines we purchase that have been allocated to a qualified project, (ii) 60% of the contract price of the turbines we purchase that have not been allocated to a qualified project, (iii) all interest and fees under the facility, and (iv) 80% of the historic financing costs with respect to the turbine supply agreements in an aggregate amount not to exceed $18.2 million. To the extent that borrowings under the first lien revolving turbine credit facility exceed this amount and in certain other circumstances, we may be required to make prepayments under the first lien revolving turbine credit facility. Certain windparks identified in the first lien revolving turbine credit facility have been pre-approved as qualified projects. Further windparks need to be approved by a committee of lenders and the administrative agent (based on procedures and criteria specified in the first lien revolving turbine credit facility) in order to become qualified projects. Projects can lose their status as "qualified projects" for various reasons specified in the first lien revolving turbine credit facility, including (i) circumstances in which it is clear (based on specified procedures, which include independent third-party review by the specified engineer if the parties are unable to agree) that the particular project will not achieve completion sufficiently in advance of the expiration date for PTCs applicable to such project and (ii) circumstances in which the equity interests in the applicable owner of the applicable project have not been pledged to the lenders as required under the first lien revolving turbine credit facility. The first lien revolving turbine credit facility also requires that we maintain a minimum equity investment in NEP Equipment Finance Co., LLC, which we provide for in part through borrowings under the second lien turbine credit facility.

        Our subsidiary, NEP Equipment Finance Hold Co., LLC, has borrowed $260.0 million under the second lien turbine credit facility, which bears interest at a rate of 15% per annum and matures in July 2010. We may voluntarily make repayments of the second lien turbine credit facility at any time, with voluntary prepayments made prior to October 26, 2008 being subject to a make-whole premium and voluntary prepayments made thereafter not being subject to premium or penalty. We are required to make prepayments of the second lien turbine credit facility to the extent that the amount outstanding under the facility exceeds the sum of: (i) the positive difference (if any) between the aggregate contract price paid under all turbine supply agreements (subject to certain adjustments) and any amounts borrowed under the first lien revolving turbine credit facility plus (ii) $40 million. As of April 21, 2008 we were not required to make any prepayments of the amounts borrowed under the second lien turbine credit facility as those amounts were $2.4 million less than the amounts calculated pursuant to the sentence above.

        Obligations under the second lien turbine credit facility are secured by second priority liens on the assets that secure the first lien revolving turbine credit facility and by a first priority pledge of the membership interests in NEP Equipment Finance Hold Co., LLC, the parent company of NEP Equipment Finance Co., LLC, the borrower under the turbine credit facilities and in Noble Environmental Power 2009 Equipment Co., LLC, a party to a turbine supply agreement with GE, as well as a first priority pledge of the rights of Noble Environmental Power 2009 Equipment Co. in such

54



turbine supply agreement. The pledge with respect to Noble Environmental Power 2009 Equipment Co. will become a second priority pledge at such time as it is required to be pledged under the first lien revolving turbine credit facility.

        Each of the turbine credit facilities contains certain restrictive covenants that restrict the actions of the borrower as well as customary affirmative covenants and events of default.

        For a further discussion of the first and second lien turbine credit facilities, see "—Capital Structure and Financial Resources" and "Description of Certain Financing Arrangements—Senior Secured Turbine Credit Facilities."

Wind Park Development Financing

        During the development phase of a particular windpark—the phase during which our efforts are focused on an analysis of feasibility, acquisition of real property rights, pre-construction engineering and permitting, but prior to the commencement of construction—lenders are typically unwilling to finance our operations with debt on terms that are acceptable to us due to the relative uncertainties associated with such early-stage projects. As a result, we have historically funded cash requirements during this period through equity contributions funded or debt guaranteed by our sponsors and in the future expect to fund such cash requirements with a combination of cash flows from operations as well as the proceeds of this offering and possible future equity or debt offerings. We seek to minimize cash expenditures during the development phase for our windparks.

Wind Park Construction Financing

        After we have advanced the development of a particular windpark to the point where we are prepared to commence construction of the windpark, we typically enter into a limited recourse project construction loan. The proceeds of a project construction loan are used to, among other things, (i) make repayments of amounts drawn on our turbine credit facilities with respect to turbines deployed in the applicable windpark, (ii) fund the cash required to complete construction and commence operations of the applicable windpark, including additional payments under our turbine supply agreements and (iii) fund the costs of the construction loan itself, including fees and interest incurred during the construction period. For a further discussion of the project financing facility that we entered into in connection with the construction of the Initial New York Windparks, see "Description of Certain Financing Arrangements—Initial New York Project Financing." At the time that we enter into a project construction loan, we also make cash equity contributions, the amount of which is dependent on the total estimated cost to construct the windpark, the amount of equity previously invested in the windpark, the predicted performance characteristics of the windpark based upon meteorological data that we have gathered and the associated revenues and expenses resulting in the final anticipated capital structure of the windpark. These cash contributions have historically been funded by our sponsors and in the future we expect to fund these cash requirements with a combination of cash flows from operations as well as the proceeds of this offering and possible future equity or debt offerings. In the case of the Initial New York Windparks, we made an initial cash equity contributions of approximately $88.5 million, and secured a project construction loan of $305.4 million, as well as an equity bridge loan of $179.6 million, for a total financing of $485.0 million.

Refinancing Upon Commencement of Commercial Operations and Tax Equity Financing

        Once construction of a windpark is completed and commercial operations have commenced, our financing requirements with respect to that windpark will depend on the type of tax equity financing we obtain for that windpark, which we expect to generally follow one of the following two approaches:

    In certain cases, when a windpark commences commercial operations, a portion of the construction loan automatically converts into a long-term loan facility, typically with a 10- to 15-year term. The remaining portion of the construction loan is then repaid using (i) the cash proceeds of equity investments in the applicable windpark by tax equity investors who make

55


      contributions at the time that the applicable windpark commences operations, as well as additional fixed and contingent (based on kWhs produced) contributions over a period of time up to ten years and (ii) in some cases, additional cash equity contributions from us. We refer to this form of tax equity financing as an Additional Equity Contribution partnership, or AEC, structure. See "Business—Organization of Our Business—Financing and Commodities Risk Management—Project Financing—Tax Equity Financing."

    In other cases, we expect that when a windpark commences commercial operations all of the project construction loan will be repaid at that time using (i) the cash proceeds of equity investments by tax equity investors who make their entire contribution at the time the applicable windpark commences operations, (ii) additional cash equity contributions from us, which additional cash equity contribution may be funded by a loan at the member level and (iii) possibly a term loan at the project company or project holding company level in certain circumstances. We refer to this form of tax equity financing as a pre-tax, after-tax partnership structure or PAPS, structure. See "Business—Organization of Our Business—Financing and Commodities Risk Management—Project Financing—Tax Equity Financing."

        We expect to fund any additional cash equity contributions required from us through a combination of a portion of the proceeds of this offering, future equity or debt offerings and expected cash flow from operations. In addition, we expect that tax equity financings of our future windparks will comply with an IRS safe harbor for wind credit investment structures.

        We have the intent and the ability to refinance the outstanding $485.0 million of the Initial New York Windparks' construction loan and equity bridge loan as follows:

    approximately $324.7 million of the construction and equity bridge loans will be converted into a ten-year term loan facility; and

    tax-equity investors will make an equity investment of approximately $220 million in NEP NY 2006, our subsidiary that owns the Initial New York Windparks.

        On May 7, 2008, we issued a notice of term conversion to Dexia Credit Local, New York Branch, or Dexia, and to our tax equity investors. The notice triggers the conversion of our construction loan and a portion of our equity bridge loan to a term loan, and triggers the requirement for the tax equity investors' investment in NEP NY 2006. The conversion is expected to take place within four banking days from the date of the notice. The tax equity investment will occur simultaneously with the term conversion closing.

        In addition, we expect that the tax equity investors in the Initial New York Windparks will contribute additional amounts at the end of each fiscal quarter based on the amounts of PTCs generated by the Initial New York Windparks.

        In future windparks under the AEC structure, a portion of the payments will be fixed and the remaining payments will be contingent to conform to an IRS safe harbor for wind credit investment structures. This expected stream of additional cash flows based on energy production is added to the cash available for debt service and enables us to support a larger term loan.

        The terms of our relationship with the tax equity investors in the Initial New York Windparks will be governed by the limited liability company agreement of NEP NY 2006. We refer to this operating agreement as the New York 2006 LLC Agreement, and we expect that this agreement will be executed prior to the completion of this offering.

        The New York 2006 LLC Agreement will provide that we will control the day-to-day operations of NEP NY 2006 with most material actions requiring the agreement of the tax equity investor. The New York 2006 LLC Agreement will also govern the sharing of cash flows and tax attributes between us and the tax-equity investor. As shown in the table below, the allocation of cash flows will change at two defined points in time. In general, all cash available after debt service will be distributed to us until the earlier of (i) the date our capital account in NEP NY 2006 is first reduced to zero or (ii) the date our capital account is projected to first reach zero under certain probability modeling. We refer to this date

56



as the "cash flip." After the cash flip, all cash available after debt service will be distributed to the tax-equity investor, or used to prepay the term loan, until the earlier of (i) the later of the tenth anniversary of the tax equity investor's equity capital contribution date or the date the tax equity investor achieves its target rate of return, or "flip rate," taking into account both tax attributes and cash distributions and (ii) the date the tax equity investors reach the flip rate and the term loan is repaid. We refer to this date as the "flip point." At all times until the flip point, all of the tax attributes associated with NEP NY 2006 (specifically, the PTCs and the accelerated depreciation) will be allocated to the tax equity investor. In the event the IRS were to successfully challenge these allocations based on non-binding guidance issued prior to the equity capital contribution date, or such guidance becomes binding law, and the allocations are negatively impacted, the flip point could be delayed. After the flip point, the tax equity investor will retain a small residual equity interest in the entity, with all other cash distributed to us.

 
  Cash Distributions
  PTCs and Depreciation(1)
 
 
  Noble
  Investor
  Noble
  Investor
 
Year One — Cash Flip   100 % 0 % 0 % 100% (2)
Cash Flip — Flip Point   0 % 100 % 0 % 100% (2)
After Flip Point   95 % 5 % 95 % 5 %

      (1)
      PTCs provide the tax investor with a tax credit based on energy revenues against federal income taxes for a ten-year period following the date that the relevant wind turbine is placed in service. Most windpark assets are depreciable over a 5-year period after the commencement of operations.

      (2)
      In future windparks, PTCs and depreciation generally will be allocated 99% to the Investor and 1% to Noble over the initial 10-year period to conform to an IRS safe harbor for wind credit investment structures.

        Tax equity investors are willing to provide us with relatively low-cost capital because they can use the PTCs and accelerated depreciation generated by the windparks to offset their taxable income. Given our history of operating losses, and the fact that we expect such losses to continue, we cannot, and do not in the foreseeable future expect to be able to, use these tax attributes to reduce our own taxes.

Historical Cash Flows

        Our cash flows for the periods discussed below were as follows:

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
 
  (in thousands)

 
Cash flows provided (used) by operating activities   $ 39,921   $ (20,210 ) $ (6,036 )
Cash flows used by investing activities     (617,867 )   (507,141 )   (47,206 )
Cash flows provided by financing activities     618,043     532,591     54,375  

    Cash Flows for the Year Ended December 31, 2007

        Net cash provided by operating activities for the year ended December 31, 2007 was $40.0 million, as compared with net cash used by operating activities of $20.2 million for the year ended December 31, 2006. The increase in cash provided by operating activities of $60.2 million was due to a net increase in accounts payable and accrued expenses of $69.5 million and an increase in non-cash adjustments of $16.2 million offset by increases in net loss of $21.8 million and other current and noncurrent assets of $3.7 million.

        Net cash used by investing activities for the year ended December 31, 2007 was $617.9 million, as compared with $507.1 million for the year ended December 31, 2006. The increase in cash used by investing activities of $110.8 million resulted from increased capitalized spending of approximately

57



$86.4 million associated primarily with project development, construction and wind turbine and transportation costs. In addition, our restricted cash balances, primarily associated with collateral requirements on our outstanding letters of credit, increased by $24.4 million during the year ended December 31, 2007, as compared to the year ended December 31, 2006.

        Net cash provided by financing activities for the year ended December 31, 2007 was $618.0 million, as compared with $532.6 million provided by financing activities for the year ended December 31, 2006. The increase in cash provided by financing activities of $85.4 million resulted from increased borrowings (net of repayments and deferred costs) under our turbine supply and related credit facilities (approximately $116.3 million) offset by a decrease in equity contributions of approximately $30.2 million and an increase in deferred offering costs of $0.7 million during the year ended December 31, 2007, as compared to the year ended December 31, 2006.

    Cash Flows for the Year Ended December 31, 2006

        Net cash used by operating activities for the year ended December 31, 2006 was $20.2 million, as compared with $6.0 million for the year ended December 31, 2005. This $14.2 million increase was principally attributable to the increase in net loss of approximately $12.9 million and operating cash use due to changes in assets and liabilities of approximately $7.5 million, offset by the effect of non-cash adjustments to net loss of approximately $6.2 million due mainly to the 2006 $5.5 million write-off of construction in progress.

        Net cash used by investing activities for the year ended December 31, 2006 was $507.1 million, as compared with $47.2 million for the year ended December 31, 2005. This $459.9 million increase was principally attributable to the increase in capitalized spending of $366.9 million and construction material deposits for wind turbines of $80.1 million made during the year ended December 31, 2006, as compared to the year ended December 31, 2005. In addition, our restricted cash balances, primarily associated with collateral requirements on our outstanding letters of credit, increased by approximately $12.9 million during the year ended December 31, 2006, as compared to the year ended December 31, 2005.

        Net cash provided by financing activities for the year ended December 31, 2006 was $532.6 million, as compared with $54.4 million for the year ended December 31, 2005. This $478.2 million increase was principally due to increased borrowings and deferred financing costs on our turbine supply agreements and related credit facilities of approximately $333.7 million and increase in equity contributions of approximately $144.5 million during the year ended December 31, 2006, as compared to the year ended December 31, 2005.

Capital Structure and Financial Resources

        At December 31, 2007, our debt consisted of:

    $490.1 million of borrowings under our turbine financing arrangements;

    $257.1 million and $179.6 million of borrowings under the construction loan and equity bridge loan portions of our project finance loan, respectively, related to the Initial New York Windparks; and

    $31.5 million in letters of credit issued under our project construction loan.

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Contractual Obligations

        The following table sets forth our material contractual obligations as of December 31, 2007, excluding interest and our obligations under the hedging arrangements with Credit Suisse:

 
  Payments due by period
Description
  Total
  Less than
1 year

  1-3 years
  4-5 years
  More than
5 years

 
  (in thousands)
Long-term debt   $ 926,791   $   $ 513,866   $ 58,962   $ $353,963
Capital lease obligation                    
Operating lease obligations     7,584     4,313     2,966     305    
Purchase obligations     1,011,250     595,528     384,579     5,028     26,115
Asset retirement obligations     10,228                 10,228
Other long-term liabilities                    
   
 
 
 
 
Total   $ 1,955,853   $ 599,841   $ 901,411   $ 64,295   $ 390,306
   
 
 
 
 

        The above schedule excludes certain of our long-term commitments that are not quantifiable until paid. Such commitments include payments to be made under our easement contracts, interest under variable rate arrangements and distributions to our tax equity investors. This table also does not include the payments that we will make to Credit Suisse under our financial energy hedging agreement. See "—Revenues."

        In accordance with SFAS 6, "Classification of Short-Term Obligations Expected to be Refinanced," we have classified amounts due under the construction and equity bridge loans as long-term debt at December 31, 2007. Such classification is deemed appropriate as we have both the intent and ability to refinance these obligations.

Off-Balance Sheet Arrangements

        We do not have any off-balance sheet arrangements, other than letters of credit issued in the ordinary course of business, that have or are reasonable likely to have a material current effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Quantitative and Qualitative Disclosures About Market Risk

        We are exposed to market risks from changes in energy prices and interest rates, which may affect our results of operations and financial condition, and consequently our fair value.

Changes in Energy Prices

        Although our strategy involves executing financial hedges designed to limit our exposure to fluctuations in electricity prices, a portion of the revenues that our windparks generate are unhedged and therefore depend on market prices of electricity. Market prices for both electricity and capacity are volatile and depend on numerous factors including economic conditions, population growth, electrical load growth, government policy, weather, the availability of alternate generation and transmission facilities and the price of natural gas and alternative fuels or energy sources. We cannot assure you that market prices will be at levels that enable us to operate profitably or as anticipated. We have entered into a financial energy hedging agreement for our Initial New York Windparks which will limit our exposure to volatility in energy prices for approximately 80% of the expected annual production of these facilities during the first ten years of their operation. Because we have not entered into any hedges for the initial New York Windparks beyond the first ten years of operation, and have not executed any hedges for any of our other windparks, a decline in energy market prices below

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anticipated levels could have a material adverse impact on our revenues or results of operations, and could restrict or eliminate our ability to develop, finance, and complete planned windparks for which hedging transaction have not yet been executed. Because we have not executed contracts to sell the capacity of any of our windparks, a decline in capacity market prices below anticipated levels could have a material adverse impact on our revenues.

        Although we have agreed to sell approximately 95% of the RECs we anticipate generating from our Initial New York Windparks and our windparks in New York that are expected to commence operations in 2008 under executed ten-year fixed price contracts, a small portion of the RECs we expect our Initial New York Windparks to generate, and all of the RECs that our other windparks are expected to generate are not currently under contract and will be subject to the availability of contracts and changes in market prices. Any increases in the market supply of RECs, a decrease in the market price of RECs or changes in state and federal regulatory policy may decrease our ability to sell RECs in the volumes we forecast or could reduce the sales price of our RECs, which could have a material adverse impact on our revenues.

        We use and plan to continue using derivative financial instruments, such as our hedging agreement with Credit Suisse, to manage market risks and reduce our exposure to fluctuating electricity prices. These activities expose us to certain market risks, including unsuccessful matching of exposures or execution of our hedging strategy, and limit our ability to realize the full benefits of increases in energy prices. Our hedging strategy may not be effective in controlling risk within prescribed boundaries or limits as expected. In addition, future changes in markets may not be consistent with our historical data or assumptions. If we are not able to successfully anticipate and hedge against market risks, volatile electricity prices may have a material adverse effect on our business, results of operations and financial condition.

        We believe that managing our energy price exposure will reduce the volatility implicit in our business. However, it will also tend to reduce our ability to benefit from favorable energy price changes. Finally, hedging arrangements expose us to risk of financial loss if a counterparty defaults.

Changes in Interest Rates

        We are subject to interest rate risk under our bank facilities where the rate varies with changes in LIBOR rates. Although the first lien revolving turbine credit facility and the construction loan and equity bridge loan entered into in connection with the Initial New York Windparks each have variable interest rates that are based upon LIBOR, these loan facilities are used to finance construction activities and the related interest costs are capitalized. We have entered into interest swap contracts to protect against changes in the benchmark LIBOR interest rate on the variability of the specified future LIBOR interest payments relating to all but $20.0 million of the expected principal of our future Dexia term loan facility. As a result, a hypothetical 100 basis point increase in interest rates would have no more than a $0.2 million impact on our annual interest expense.

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DESCRIPTION OF CERTAIN FINANCING ARRANGEMENTS

Senior Secured Turbine Credit Facilities

First Lien Revolving Turbine Credit Facility

        In October 2007, our indirect subsidiary, NEP Equipment Finance Co., LLC, as the borrower, entered into a revolving first lien senior secured promissory note, or the First Lien Revolving Turbine Credit Facility, with HSH Nordbank AG, New York Branch, as collateral agent, administrative agent and mandated lead arranger, KeyBank National Association, as lead arranger, and certain other financial institutions as lenders. Borrowings under the First Lien Revolving Turbine Credit Facility are used to finance the purchase of wind turbines under certain turbine supply agreements between certain of our subsidiaries and GE. The First Lien Revolving Turbine Credit Facility provides for up to $460.0 million in borrowings and will mature in March 2010. As of December 31, 2007, we had $230.1 million of indebtedness outstanding under this facility.

    Loan Maximum Outstanding

        The maximum amount of loans that can be outstanding at any time under the First Lien Revolving Turbine Credit Facility is the sum of (i) 80% of the amount of the contract price under the turbine supply agreements (excluding amounts solely attributable to transportation costs), as the contract price may be adjusted from time to time (including in connection with the permitted exercise of options to purchase additional equipment or services under those agreements and as may be necessary to give effect to any reduction associated with any appraisal (as described below) of turbines required under the First Lien Revolving Turbine Credit Facility), provided that if any turbine has not been allocated to a qualified project, the percentage specified above shall be reduced to 60%, (ii) all interest and fees under the First Lien Revolving Turbine Credit Facility and (iii) 80% of the historic financing costs in respect of the turbine supply agreements in an aggregate amount not to exceed $18.2 million.

        Certain projects identified in the First Lien Revolving Turbine Credit Facility have been pre-approved as qualified projects. Further projects need to be approved by a committee of lenders and the administrative agent (based on procedures and criteria specified in the First Lien Revolving Turbine Credit Facility) in order to become qualified projects. Projects can lose their status as "qualified projects" for various reasons specified in the First Lien Revolving Turbine Credit Facility, including (i) circumstances in which it is clear (based on specified procedures, which include independent third-party review by a specified engineer if the parties are unable to agree) that the particular project will not achieve completion sufficiently in advance of the expiration date for PTCs applicable to such project and (ii) circumstances in which the equity interests in the applicable owner of the applicable project have not been pledged to the lenders as required under the First Lien Revolving Turbine Credit Facility.

        In addition to the foregoing, if the then-current expiration date for PTCs has not been extended beyond December 31, 2009 (with tax benefits similar to or better than the PTCs applicable under the current PTC), the maximum amount that we are entitled to draw under the First Lien Revolving Turbine Credit Facility with respect to turbines to be purchased by Noble Environmental Power 2009 Equipment Co. under its turbine supply agreement is $150.0 million.

    Required Take Out and Appraisal

        On or prior to the dates specified in the First Lien Revolving Turbine Credit Facility, we are required to have repaid a portion of the indebtedness under the First Lien Revolving Turbine Credit Facility applicable to certain turbines (based on the turbine supply agreement under which such turbines were purchased). In event that amounts are not so repaid, so long as the warranty under the applicable turbine supply agreements will be in effect for at least 24 months after the expected

61


commercial operation date of the project to which such turbines have been allocated, the applicable turbines are subjected to an appraisal procedure specified in the First Lien Revolving Turbine Credit Facility. If the appraisal indicates a value that is more than 3% less than the purchase price under the applicable turbine supply agreement, we are required to recalculate the amount of indebtedness permitted to be outstanding under the First Lien Revolving Turbine Credit Facility (using 80% or 60%, as applicable, of the appraised value, as opposed to the purchase price) and repay the difference. This appraisal procedure is repeated every four months until the indebtedness applicable to such turbines has been repaid. If, during appraisal procedure process, the warranty under the applicable turbine supply agreements will not be in effect for at least 24 months after the expected commercial operation date of the project to which such turbines have been allocated, we are required to immediately repay all indebtedness in respect of such turbines.

    Interest Rate and Fees

        All borrowings under the First Lien Revolving Turbine Credit Facility accrue interest, at the election of the borrower, at LIBOR plus a margin equal to 2.75% per annum or a prime rate plus a margin equal to 1.75% per annum. In addition to paying interest on the outstanding principal under the First Lien Revolving Turbine Credit Facility, we are also required to pay a commitment fee equal to 1.375% per annum of the daily average undrawn portion of the First Lien Revolving Turbine Credit Facility, which shall accrue from October 2007 and is payable quarterly in arrears.

    Equity Investment

        The First Lien Revolving Turbine Credit Facility provides that NEP Equipment Finance Hold Co., LLC, the parent of the borrower and one of our subsidiaries, from time to time shall invest equity in the borrower such that its investment is at all times equal to or greater than the aggregate of:

    (i)
    25% of the amount of first lien senior loans outstanding (other than loans applied to the contract price at the 60% advance rate described above);

    (ii)
    66.66% of the amount of loans applied to the contract price at the 60% advance rate described above; and

    (iii)
    the amount by which the Loan Maximum Outstanding described above may be reduced from time to time due to an appraisal.

        NEP Equipment Finance Hold Co., LLC has raised financing for the equity investment through the Second Lien Turbine Credit Facility described below.

    Prepayments

        The borrower may voluntarily prepay the First Lien Revolving Turbine Credit Facility in whole or in part at any time without premium or penalty. The borrower is obligated to make a mandatory prepayment of loans under the First Lien Revolving Turbine Credit Facility:

    (i)
    to the extent that the Loan Maximum Outstanding as described above is exceeded (including after giving effect to any reduction in the Loan Maximum Outstanding resulting from the removal of the turbines or termination of any turbine supply agreement or any failure to have turbines thereunder allocated to a qualified project);

    (ii)
    as and when specified above under the heading "Required Take Out and Appraisal;" and

    (iii)
    to the extent that amounts available to be borrowed under the First Lien Revolving Turbine Credit Facility (together with any equity and permitted alternative debt funding sources available to the borrower) are less than the aggregate contract price remaining to be paid for

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      turbines financed under the turbine supply agreements (in excess of a 10% payment to be made at the commissioning of turbines).

    Security

        The borrower's obligations under the First Lien Revolving Turbine Credit Facility are secured by a first priority lien on substantially all of the assets of the borrower (which consist primarily of its ownership interests in the equity interests of our subsidiaries who are parties to the turbine supply agreements) and a first priority pledge of the equity interests in the borrower by NEP Equipment Finance Hold Co., LLC, as well as the turbine supply agreements (and the turbines supplied thereunder).

    Certain Covenants and Events of Default

        The First Lien Revolving Turbine Credit Facility contains a number of covenants that restrict, among other things and subject to certain exceptions, the borrower's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, dissolve, pay dividends and make other distributions and change its business. The First Lien Revolving Turbine Credit Facility also includes customary affirmative covenants and events of default (including a cross-default to our Second Lien Turbine Credit Facility described below) as well as a requirement to maintain sufficient availability (through the First Lien Revolving Turbine Credit Facility or other acceptable financing sources, including equity) in order to permit us to make required payments under the turbine supply agreements and to pay the related interest and fees.

Second Lien Turbine Credit Facility

        In October 2007, NEP Equipment Finance Hold Co., LLC, as the borrower, entered into a second lien secured promissory note, or the Second Lien Turbine Credit Facility, with Paragon Noble LLC, as lender, to finance NEP Equipment Finance Hold Co., LLC's obligations to make equity investment under the First Lien Revolving Turbine Credit Facility. The Second Lien Turbine Credit Facility provides for a $260.0 million senior secured term loan that will mature in July 2010. As of December 31, 2007, we had $260.0 million of indebtedness outstanding under this facility.

    Interest Rate

        All borrowings under the Second Lien Turbine Credit Facility accrue interest at 15% per annum.

    Prepayments

        After October 26, 2008, the borrower may voluntarily prepay the Second Lien Turbine Credit Facility in whole or in part at any time without premium or penalty. Voluntary prepayments made prior to October 26, 2008 are subject to a make-whole premium based on the U.S. Treasury rate plus 50 basis points.

        If the principal amount outstanding under the Second Lien Turbine Credit Facility ever exceeds the aggregate of (i) the positive difference, if any, between the amount of the aggregate contract price paid under all turbine supply agreements (excluding amounts solely attributable to transportation costs but reflecting applicable adjustments, if any, pursuant to the permitted exercise of options to purchase additional turbines under those agreements or any reduction associated with any appraisal of turbines required under the First Lien Revolving Turbine Credit Facility) and any amounts borrowed under the First Lien Revolving Turbine Credit Facility and used to fund such payments plus (ii) $40.0 million, the borrower is required to make a mandatory prepayment of the loans in an amount equal to such excess (which amounts may not be reborrowed) or to post cash collateral in amount equal to such excess

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(which amount can be withdrawn to the extent such excess no longer exists). Any mandatory prepayment will be without premium or penalty.

    Guarantee and Security

        The obligations under the Second Lien Turbine Credit Facility are secured by a second priority lien on the assets that secure the First Lien Revolving Turbine Credit Facility. NEP Equipment Finance Hold Co., LLC's obligations under the Second Lien Turbine Credit Facility are also secured by a first priority pledge of the membership interests in NEP Equipment Finance Hold Co., LLC and in Noble Environmental Power 2009 Equipment Co., LLC, a party to a turbine supply agreement with GE, as well as a first priority pledge of the rights of Noble Environmental Power 2009 Equipment Co. in such turbine supply agreement. The pledge with respect to Noble Environmental Power 2009 Equipment Co. will become a second priority pledge at such time as it is required to be pledged under the First Lien Revolving Turbine Credit Facility.

        The obligations under the Second Lien Turbine Credit Facility are also supported by a guarantee by Noble Environmental Power, LLC. The guarantee contains a number of covenants that restrict, among other things and subject to certain exceptions, Noble Environmental Power, LLC's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests in the borrower under the Second Lien Turbine Credit Facility, dissolve or enter into certain merger transactions. The guarantee also contains customary representations and warranties and reporting requirements.

    Certain Covenants and Events of Default

        The Second Lien Turbine Credit Facility contains a number of covenants that restrict, among other things and subject to certain exceptions, the borrower's ability to incur debt, grant liens, sell or lease certain assets, transfer equity interests, any dividends, dissolve or change its business. The Second Lien Turbine Credit Facility also includes customary affirmative covenants and events of default.

Letter of Credit Facility

        On February 14, 2008, our subsidiary, Noble Credit Funding, LLC, or Noble Credit, entered into a Master Credit Agreement with RBS Citizens, National Association, or RBS. The Master Credit Agreement is a revolving letter of credit facility, under which RBS may issue, on behalf of Noble Credit or any of its affiliates, one or more standby letters of credit to third parties, subject to the terms and conditions set forth in the Master Credit Agreement.

        The maximum amount of letter of credit obligations that may be outstanding at any time under the Master Credit Agreement is $45.0 million. The Master Credit Agreement expires on February 14, 2010, and all letters of credit issued under the agreement must expire at least ten days prior to such date. As of April 28, 2008, there was a face amount of $30.3 million outstanding under letters of credit issued pursuant to the Master Credit Agreement.

        Noble Credit is required to cash collateralize 100% of the face value of each letter of credit issued under the Master Credit Agreement. Pursuant to a Pledge and Security Agreement, Noble Credit granted RBS a security interest in any cash collateral, provided that RBS may not foreclose on any cash collateral if such foreclosure would lead to the cancellation of any outstanding letter of credit. In addition, Noble Credit issued to RBS a Revolving Credit Note, under which RBS may demand payment of any fees or expenses payable to RBS if Noble Credit does not pay on a timely basis or if RBS is unable to access the cash collateral after a certain period. Neither Noble Credit's failure to pay any fees or other amounts due under the Master Credit Agreement nor the existence of an obligation under the Revolving Credit Note gives RBS the right to cancel any outstanding letter of credit.

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Initial New York Project Financing

Construction Loan, Equity Bridge Loan, Term Loan and Letters of Credit

        In June 2007, an indirect subsidiary of the company, Noble Environmental Power 2006 Hold Co, LLC, which we refer to as NEP NY 2006, entered into a financing agreement with (i) Dexia Credit Local, New York Branch, as lead arranger, joint bookrunner, technical and documentation agent, co-syndication agent, LC fronting bank and administrative agent for the lenders, (ii) HSH Nordbank AG, New York Branch, as lead arranger, joint bookrunner and co-syndication agent and (iii) the other lenders party thereto to fund the Initial New York Windparks. The financing provided for a construction loan of up to $305.4 million in the aggregate and an equity bridge loan of up to $179.6 million, each with a maturity date of May 16, 2008. In addition, in connection with the construction loan, we provided a maximum $15.0 million guaranty to cover cost overruns, completion reserves and the repayment of any portion of the construction loan that could not be converted.

        Upon the satisfaction of the conditions in the financing agreement, which include the investment of tax equity in NEP NY 2006, the construction loan and a portion of the equity bridge loan will convert into a term loan. We refer to the date of this conversion as term conversion. There is also an additional $76.5 million available in letters of credit (of which no more than $45.0 million can be outstanding under the energy hedge letter of credit and no more than $31.5 million can be outstanding under the debt service reserve account letter of credit). The term loan and the letters of credit will mature approximately ten years after the date of term conversion. Additionally, upon term conversion, a portion of the equity bridge loan discussed above will be repaid from the proceeds of the initial equity investment by EFS Noble Holdings, LLC, a wholly-owned subsidiary of General Electric Capital Corporation, in the borrower.

    Interest Rate

        All borrowings under the construction loan and the equity bridge loan accrue interest at LIBOR plus:

    (i)
    1.375% from June 22, 2007 to July 30, 2007; and

    (ii)
    1.250% from and including July 30, 2007, to but excluding the date of term conversion.

        All borrowings under the term loan will accrue interest at LIBOR plus:

    (i)
    1.250% from and including the date of term conversion to but excluding the fifth annual anniversary thereof;

    (ii)
    1.375% from and including the fifth annual anniversary of the date of term conversion to but excluding the ninth annual anniversary thereof; and

    (iii)
    1.500% from and including the ninth anniversary of the Term Conversion Date to and including the date the term loan matures.

    Distribution Reserve Account

        Amounts that would otherwise be available for distribution to the equity holders except for the failure to meet the distribution requirements will be held in the distribution reserve account until such distribution requirements are met. The distribution requirements include that distributions may be made only after the first repayment date following commencement of operations at our windparks, that no event of default has occurred or is continuing and that the reserve and other accounts are fully funded. Any amounts held in the distribution reserve account for more than twenty-four consecutive months will be used to prepay the loans.

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    Prepayments

        The borrower may, at its option, prepay the construction loan, the equity bridge loan, the term loan, the debt service reserve account letter of credit or the energy hedge letter of credit, provided that, after giving effect to any such prepayment, the outstanding obligations under such loans do not exceed $20.0 million in the aggregate. The borrower is only permitted to make such prepayment if concurrently with such prepayment it replaces the energy hedge letter of credit issued by Dexia (without causing any draw by the energy hedge provider on such energy hedge letter of credit) with a replacement energy hedge letter of credit issued by a person acceptable to the energy hedge provider.

        The borrower is obligated to make a mandatory prepayment of loans:

    (i)
    to the extent a change in law makes it unlawful or impossible for a lender to make or maintain the loans and

    (ii)
    to the extent that any amounts have remained undisbursed in the distribution reserve account for 24 consecutive months.

    Security

        The borrower's obligations under the construction and equity bridge loans are, and the term loan will be, secured by a first priority lien, subject to certain permitted liens, on the assets of the borrower including its interest in the project companies which own the Initial New York Windparks, and a first priority pledge of the equity interests in the borrower by our wholly-owned subsidiary, Noble Environmental Power Hold Co. Prime, LLC, which we refer to as Noble Prime, as well as pledges of the equity interests in the borrower's subsidiaries and their assets (including the turbine supply agreements). The borrower's obligations under the construction and equity bridge loans are, and the term loan will be, also secured by a first priority pledge of the equity interests in the borrower by EFS Noble Holdings.

    Certain Covenants and Events of Default of Term Loan

        The construction loan and equity bridge loan contain and the term loan will contain a number of covenants including those that restrict, subject to certain exceptions, the borrower's ability to incur other debt, grant liens, sell or lease certain assets, transfer equity interests, lose material permits, modify permits, modify documents, dissolve, pay dividends and make other distributions and change its business. The construction loan and the equity bridge loan include and the term loan will include customary affirmative covenants and events of default, including a cross-default for certain other debt of the borrower and its subsidiaries.

Membership Interest Purchase and Equity Capital Contribution Agreement

        In June 2007, Noble Prime and NEP NY 2006 entered into a Membership Interest Purchase and Equity Capital Contribution Agreement, or ECCA, with EFS Noble Holdings, LLC, an affiliate of GE, which we refer to as EFS. Pursuant to the ECCA, on the date of term conversion, NEP NY 2006 will issue (i) Class A membership interests to the Class A members in exchange for the equity capital contribution of the Class A members, and (ii) Class B membership interests to Noble Prime in exchange for Noble Prime's original membership interests in NEP NY 2006. The ECCA provides for the equity capital contribution of the Class A members to be made in up to four installments. The amount of the initial equity capital contribution made on the term conversion date will be based on the number of wind turbines in our Initial New York Windparks that have achieved substantial completion as of such date. If applicable, the balance of the equity capital contribution of the Class A members will be made as the remaining wind turbines achieve substantial completion.

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        Upon execution of the ECCA, Noble Environmental Power, LLC issued a guaranty in favor of the Class A member of the amounts due and payable by the Class B member to the Class A member under the indemnity provisions of the ECCA and under the New York 2006 LLC Agreement. The guaranteed amount is limited to the aggregate amount of equity capital contributions of the Class A member, less any cash distributed to such member pursuant to the New York 2006 LLC Agreement.

Pay-As-You-Go Capital Contribution Agreement

        At the time Noble Prime entered into the ECCA, it also entered into a Pay-As-You-Go Capital Contribution Agreement, or PAYG agreement, pursuant to which the Class A members have agreed to make additional capital contributions to NEP NY 2006 at the end of each fiscal quarter period based on the amount of PTCs generated by the projects. This obligation will become effective on the date of term conversion, with EFS's initial equity capital contribution, and generally will end on the date the "flip point" occurs, which will be the earlier of (i) the later of the tenth anniversary of the equity capital contribution date or the date the Class A members realize their target after-tax rate of return, or "flip rate," and (ii) the date the Class A members realize the flip rate and the term loan is repaid. The Class A members' obligations under the PAYG agreement will terminate prior to the flip point in the event title to all Class A membership interests is transferred to the term loan lenders. From and after the date on which the Class A members realize the flip rate, if the obligations of NEP NY 2006 under the term loan have not been fully repaid, NEP NY 2006 must apply all of the PAYG capital contributions relating to periods after the flip rate is realized to prepay the term loan.

        Only wind energy sold to unrelated parties qualifies for the PTC. However, the parties have agreed that if a Class A member or its affiliate becomes a related party and fails to comply with its obligations under the New York 2006 LLC Agreement to take all actions necessary to cease being a related party (and Noble Prime complied with its obligations under the New York 2006 LLC Agreement), the PAYG capital contributions will be made as if the Class A member had not become a related party. Conversely, if a Class A member becomes a related party as a result of Noble Prime's failure to comply with its obligations under the New York 2006 LLC Agreement, then the PAYG capital contributions will be reduced to account for the failure to qualify for PTCs and will be further reduced by the amount of any damages owed to the Class A member in accordance with the New York 2006 LLC Agreement. See also "—Amended and Restated Limited Liability Company Agreement—Indemnification Obligations—Related Party Problems."

Amended and Restated Limited Liability Company Agreement

        Pursuant to the ECCA, on the date of term conversion, Noble Prime will enter into an Amended and Restated Limited Liability Company Agreement, or New York 2006 LLC Agreement, governing NEP NY 2006 in connection with the initial equity investment by EFS in our Initial New York Windparks. NEP NY 2006 holds all the interests in three subsidiary limited liability companies, or project companies, which hold the assets of the Initial New York Windparks.

        The New York 2006 LLC Agreement will provide for two classes of membership interests, Class A membership interests and Class B membership interests. We expect that we will hold 100% of the outstanding Class B membership interests, and EFS will hold 100% of the outstanding Class A membership interests.

    Management

        Under the terms of the New York 2006 LLC Agreement, Noble Prime will be the managing member of NEP NY 2006 and will be responsible for its day-to-day operations, subject to certain approval rights of the Class A members described below. The day-to-day administration and operation

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of the projects will be delegated to our subsidiaries, Noble Management Services, LLC and Noble Wind Operations, LLC, pursuant to agreements between the project companies and these entities.

        Prior to the flip point, material actions will require the approval of Class A members holding a majority of the Class A membership interests. After the flip point, the approval rights of the Class A members will be limited to a small subset of these material actions reflecting the Class A members' reduced minority interest. Material actions will include significant matters relating to the management and operation of NEP NY 2006 and the project companies and approval of an annual operating budget.

        As managing member, Noble Prime will be required to perform its obligations under the New York 2006 LLC Agreement in accordance with the terms of the agreement and the standards set forth therein. As managing member, Noble Prime will be required to perform its duties and its obligations at all times in good faith and in the best interest of NEP NY 2006 and the project companies. In addition, in instances involving, directly or indirectly, the construction, operation and management of the Initial New York Windparks, Noble Prime will be required to act in accordance with a prudent operator standard. In discharging its duties as managing member, Noble Prime will be permitted to rely on legal counsel, qualified industry consultants or other advisors. Noble Prime will be able to be removed as managing member only upon the occurrence of certain special events described below.

    Allocations and Distributions

        Profits, losses and other tax items (including PTCs and accelerated tax depreciation) will be allocated 100% to the Class A members until the flip point occurs. Thereafter, profits, losses and other tax items will be allocated 5% to the Class A members and 95% to the Class B members. The flip point will be the earlier of (i) the later of the tenth anniversary of the Class A members' equity capital contribution or the date the Class A members realize the flip rate, and (ii) the date the Class A members realize the flip rate and the term loan is repaid. The flip rate will be a pre-determined after-tax internal rate of return, taking into account cash contributions and distributions as well as the tax benefits (primarily PTCs and accelerated depreciation) and tax costs realized by the Class A members. The calculation of the flip rate will be done as necessary on a monthly basis by the managing member, in accordance with a model based on certain fixed assumptions relating to tax rates, depreciation methods and conventions, and the allocation of items of income, gain, loss and deduction to the members, but taking into account the actual amount of particular items realized or deemed realized by NEP NY 2006 and the project companies. In the event the IRS were to successfully challenge these allocations based on non-binding guidance issued prior to the Class A members' equity capital contribution, or such guidance were to become binding law, and the allocations are negatively impacted, the flip point could be delayed.

        Distributable cash initially will be distributed 100% to the Class B member until the earlier of (i) the date the Class B member's capital account is first reduced to zero or (ii) the date that Class B member's capital account is projected to first reach zero under certain probability modeling. Thereafter cash will be distributed 100% to the Class A members until the flip point occurs, except that if the Class A members realize their flip rate before the term loan has been repaid, then 95% of the distributable cash will be used to service the term loan. After the flip point, cash will be distributed 5% to the Class A members and 95% to the Class B member.

    Indemnification Obligations

        The New York 2006 LLC Agreement will provide that any member who breaches the New York 2006 LLC Agreement may be held liable to any other member, NEP NY 2006 or the project companies for any damages (including the value of any lost PTCs) sustained by such person as a result of the breach. In addition, members will make certain covenants to each other, the breach of which

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could result in indemnification obligations to NEP NY 2006, the project companies and/or other members, including:

    Related Party Problems.  Only wind energy sold to unrelated parties qualifies for the PTC. Accordingly, to avoid potential related party problems, as managing member, Noble Prime will be obligated to notify the members prior to entering into any power sales agreement. If Noble Prime fails to notify the members as required and, as a result, any member becomes a related party, Noble Prime will be obligated to indemnify the members for any damages (including the value of lost PTCs) suffered as a result. Conversely, if any member becomes a related party and fails to comply with its obligations to take all actions necessary to cease being a related party, such member will be obligated to indemnify NEP NY 2006, the project company and the other members for any damages (including the value of lost PTCs) suffered as a result.

    Array Loss.  The Class B member will agree not to develop or construct any windpark, other than our projects in development in Chateaugay and Bellmont, within 20 rotor diameters of the projects if it could reasonably be expected to result in a 0.5% or greater reduction of the net annual energy output of the projects, unless the Class B member agrees to compensate the affected project for any damages. If the reduction could reasonably be expected to be 2.0% or greater, the Class B member will be required to obtain the approval of a majority of the Class A members. With respect to our projects in development in Chateaugay and Bellmont, the Class B member will enter into a separate affiliate array loss agreement setting forth the terms of compensation payable to the affected projects.

    Estoppel and New York State Electric and Gas, or NYSEG, Events.  NEP NY 2006 will agree to indemnify the Class A members in certain circumstances if its failure to obtain all necessary estoppels prior to the initial equity capital contribution of EFS results in an impairment of the net annual energy output of the affected project. NEP NY 2006 similarly will agree to indemnify the Class A members in certain circumstances in the event of a dispute with NYSEG that results in an impairment of the net annual energy output of the affected project. In either case, any indemnification will be paid by means of a priority distribution of cash from NEP NY 2006.

        These indemnification rights and obligations will not be exclusive and will be in addition to any rights and remedies available to NEP NY 2006, the project company or the members at law or in equity.

    Special Events

        The New York 2006 LLC Agreement will provide that upon the occurrence of certain "special events" prior to the flip point, the Class A members may exercise the following rights, in addition to any other rights or remedies available at law or in equity, including seeking damages if the Class B member fails to cure the special event and fully indemnify the Class A members for any damages sustained as a result of the special event within 30 days of receiving notice of the special event: (i) cause NEP NY 2006 to withhold distributions otherwise payable to the Class B member; (ii) remove Noble Prime as managing member; and (iii) take material actions on behalf of NEP NY 2006 or any project company without the Class B member's consent. Special events will include: (i) the bankruptcy of NEP NY 2006 or any project company; (ii) bankruptcy of the Class B member if it has a material adverse effect; (iii) a breach or default under any principal project document if it has a material adverse effect; (iv) a default under the term loan that results in the acceleration of the obligation or a payment default that is not timely cured; (v) failure to make required distributions; (vi) a change of control of the Class B member not otherwise permitted (which will not include a change of control of Noble Environmental Power, LLC); (vii) a violation of law that has a material adverse effect or results in criminal liability of NEP NY 2006 or any project company and (viii) the commission of fraud, bad faith, willful misconduct or gross negligence.

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    Transfers

        Under the terms of the New York 2006 LLC Agreement, the members' ability to transfer their interests in NEP NY 2006 will be subject to general restrictions, including prohibitions on the transfer of interests to competitors of NEP NY 2006, persons adverse to NEP NY 2006, the project companies or the members, persons who purchase electricity from NEP NY 2006 and other disqualified transferees. In addition, the New York 2006 LLC Agreement will provide that prior to the flip point, the Class B member may not transfer more than 49% of its Class B membership interest without the consent of the Class A member, and the Class A member may only transfer its Class A membership to a transferee that meets minimum credit rating requirements and who expressly assumes the Class A member's obligations under the PAYG agreement. These same restrictions also will apply to the transfer of controlling interests in the members.

        After the flip point, if the Class B member receives a bona fide third-party offer to acquire all of the membership interests in NEP NY 2006, the Class B member will have the right to force the Class A members to join the sale provided the purchase price of the Class A membership interests is at least fair market value. If the Class B member does not elect to exercise these drag-along rights, the Class A members will have the right to force the Class B member to purchase their interests if not purchased by the third-party.

    Redemption and Buyout Rights

        The New York 2006 LLC Agreement will provide that the Class B member will have the right to purchase for fair market value all, but not less than all, of the outstanding Class A membership interests upon the later of the flip point or the tenth anniversary of the effective date of the New York 2006 LLC Agreement, and on the fifth anniversary of the later of the two dates.

        In addition, the Class B member will have the option to cause the redemption of the Class A members at a significant premium upon the occurrence of any transaction that results in a change of control of Noble Environmental Power, LLC after the fifth anniversary of the effective date of the New York 2006 LLC Agreement. The Class B member also will have the right, in certain circumstances, to cause the redemption of a Class A member that objects to any material action requiring their consent. In the case of any such redemption, the Class B member will be required to contribute sufficient cash to NEP NY 2006 necessary to enable NEP NY 2006 to redeem the Class A member or members for an amount equal to, at the option of the Class A member, fair market value or an amount that will result in the redeemed Class A members having realized a pre-determined after-tax internal rate of return.

        All members will have the right to acquire for fair market value the membership interests of any member that becomes bankrupt or can no longer legally remain a member or any Class A member that fails to maintain the minimum required credit rating.

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INDUSTRY OVERVIEW

        Renewable energy is produced using resources that are naturally replenished, such as wind, sunlight, geothermal heat, tides and biofuels. Technologies that produce energy from these renewable sources (other than biofuels) are often referred to as "clean" or "green" as they produce few, if any, pollutants that negatively impact the environment. Comparatively, fossil fuels such as coal, natural gas and oil are exhaustible and release greenhouse gases such as carbon dioxide or other pollutants into the atmosphere during energy production. As a result of increased environmental awareness, the deployment of renewable energy technologies has grown rapidly during the past several years, with 26% of new U.S. power generation capacity in 2006 consisting of renewable technologies, compared with only 2% in 2003. This increase is expected to continue, with the American Council on Renewable Energy forecasting renewable energy capacity to grow by a compounded annual growth rate of 11% through 2025, yielding a potential 550,000–700,000 MW of additional renewable capacity. At this rate, the United States could supply 25% of its electrical energy requirements with renewable energy by 2025.

        Wind energy is the fastest-growing renewable energy generation technology worldwide due to its cost efficiency, technological maturity, and the wide availability of wind resources. We believe that it has the greatest potential among all renewable energy technologies for further growth in the United States. Although the United States has hydroelectric and geothermal resources, many potential hydroelectric sites have already been developed and geothermal production is confined by geographical limitations to only certain areas of the United States. In contrast, according to the American Wind Energy Association, or AWEA, the available untapped wind resources across the United States remain vast. Additionally, other renewable energy technologies, such as solar power, are currently less economically attractive than wind energy, and others, such as biofuels, emit particulates which have a greater negative impact on the environment than wind energy.

Growth in U.S. Wind Energy

        We believe that the growth in U.S. wind energy will continue due to a number of key factors, including:

    Increases in electricity demand coupled with the rising cost of fossil fuels used for conventional energy generation resulting in increases in electricity prices;

    Heightened environmental concerns, creating legislative and popular support to reduce carbon dioxide and other greenhouse gases;

    Regulatory mandates, such as state RPS programs, as well as federal tax incentives including PTCs and accelerated tax depreciation;

    Improvements in wind energy technology;

    Increasing obstacles for the construction of conventional fuel plants; and

    Abundant wind resources in attractive energy markets within the United States.

        From its beginnings in California, wind energy in the United States has expanded steadily to 35 of the 50 states. As depicted on the maps on the next page, the total installed capacity of U.S. windparks increased by over 570% from 2,500 MW to over 16,800 MW between December 1999 and December 2007.

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GRAPHIC

Source: American Wind Energy Association, January 16, 2008

        According to AWEA, installed U.S. wind capacity increased by 2,426 MW (27%) in 2006, and over 5,244 MW (45%) in 2007. Despite this growth, wind energy generation still only represented just under 1% of U.S. electricity supply in 2006, and we believe that the prospects for further growth are very favorable. According to Emerging Energy Research, wind energy could provide approximately 50,000 MW of installed capacity in the United States by 2015. The chart on the next page illustrates the projected growth of U.S. wind capacity through 2015.

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Historical and Forecasted U.S. Installed Wind Capacity

GRAPHIC

Source: Emerging Energy Research, June 2007.

Increases in Electricity Demand Coupled with the Rising Cost of Fossil Fuels Used for Conventional Energy Generation

        The demand for electricity has historically exhibited steady growth and has increased by a cumulative amount of 22% or 656 billion kWh from 1995 through 2006. According to the Energy Information Administration, or EIA, electricity demand in the United States is forecasted to continue to grow at a steady long-term rate with a cumulative increase from 2007 through 2030 of 32%. Most of this demand has historically been supplied by coal- or natural gas-fired power plants, which accounted for 49% and 20%, respectively, of U.S. electrical power generation in 2006. Many of the most densely populated regions in the United States (including the population centers in New York, New England, Texas and California) rely on natural gas for a significant portion of their electricity production, and this high usage, combined with the increased presence of natural gas-fired power plants, has made it the fuel that determines the price of power in these markets.

        We believe that the significant increases in commodity fuel prices have spurred demand for alternative fuels such as wind energy. From 1998 to 2007, the average price of natural gas increased by approximately 235%, while the average price of oil increased by 402% over the same period. The following two charts illustrate the price increases of input fuel commodities such as crude oil and natural gas as well as retail electricity in New York and Texas.

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Indexed Price of Oil and Natural Gas

GRAPHIC

Source: Bloomberg. Average of daily oil and natural gas prices for each year during the period from 1998 to 2007.

1.
Oil index is the West Texas Intermediate crude oil spot price; 100% = $14.38 per barrel.
2.
Natural gas index is the Henry Hub average spot price; 100% = $2.08 per mmBTU.


Indexed Retail Electricity Prices

GRAPHIC

Source: Energy Information Administration.

1.
Annual average retail electricity price. Texas: 100%=6.07¢/kWh.
2.
Annual average retail electricity price. New York: 100%=10.71¢/kWh.

        Wind energy, which has no fuel costs, has become much more competitive by comparison to traditional electricity generation sources, and has grown dramatically relative to other non-hydroelectric renewable sources (including biofuels, geothermal and solar) in recent years, as shown in the following two charts.

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Comparative Cost of Electric Power Generation

GRAPHIC

Source: IEA / NEA 2005 Projected Costs of Generating Electricity, 2005.


United States Wind Generation Growth

GRAPHIC

Source: Energy Information Administration

1.
Non-hydro renewables consist of wind, solar, geothermal and biomass


        Wind energy also offers an attractive method of managing commodity price risk while maintaining strict environmental standards, as it provides a stable, affordable hedge against the risk of increases in the price of coal, natural gas and other fuels over time. Increasing the use of wind energy also has the implied benefit of lowering overall demand for natural gas, particularly during winter peak demand.

        We believe that concern over the recent increases in fuel prices in the United States, coupled with the country's significant dependence on fossil fuels, has been a factor in the political and social movement towards greater use of clean energy.

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Heightened Environmental Concerns, Creating Legislative and Popular Support to Reduce Carbon Dioxide and Other Greenhouse Gases

        The growing concern over global warming caused by greenhouse gas emissions has also contributed to the growth in the wind energy industry. According to the Intergovernmental Panel on Climate Change Fourth Assessment Report, experts have noted that eleven of the last twelve years (1995–2006) rank among the warmest years since 1850. Additionally, the global average sea level has risen at an average rate of 1.8 millimeters per year since 1961 and at 3.1 millimeters per year since 1993, due to the melting of glaciers, ice caps and polar ice sheets, coupled with thermal expansion of the oceans. The importance of reducing greenhouse gases has been recognized by the international community, as demonstrated by the signing and ratification of the Kyoto Protocol, which requires reductions in greenhouse gases by the 177 (as of March 2008) signatory nations. While the United States did not ratify the Kyoto Protocol, state-level initiatives have been undertaken to reduce greenhouse gas emissions. California was the first state to pass global warming legislation, and ten states on the east coast have signed the Regional Greenhouse Gas Initiative, which proposes to require a 10% reduction in power plant carbon dioxide emissions by 2019.

        Substituting wind energy for traditional fossil fuel-fired generation would help reduce CO2 emissions due to the environmentally-friendly attributes of wind energy. According to the EIA, the United States had the highest CO2 emissions of all countries in the world in 2005, contributing approximately 20% of the world's CO2 emissions. Since 1990, CO2 emissions from the United States' electric power industry have increased by a cumulative amount of 27%, from 1.9 billion metric tons to 2.5 billion metric tons.


Indexed Electric Power Industry CO2 Emissions: 1990–2006

         GRAPHIC

Source: Energy Information Administration

1.
1990: 100% = 1.9 Billion Metric Tons of CO2.

        Environmental legislation and regulations provide additional incentives for the development of wind energy by increasing the marginal cost of energy generated through fossil-fuel technologies. For example, regulations such as the Clean Air Interstate Rule and the Regional Haze Rule have been designed to reduce ozone concentrations, particulate emissions and haze and other requirements to control mercury emissions can require conventional energy generators to make significant expenditures, implement pollution control measures or purchase emissions credits to meet compliance requirements. These measures have increased fossil fuel-fired generators' capital and operating costs and put upward pressure on the market price of energy. Because wind energy producers are price takers in energy markets, these legislative measures effectively serve to make the return on wind energy more attractive relative to other sources of generation.

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        We believe there is significant support in the U.S. to enact legislation which will attempt to reduce the amount of carbon produced by electrical generators. Although the ultimate form of legislation is still being debated, the two most likely alternatives are (i) a direct emissions tax or (ii) a cap-and-trade regime. We believe either of these alternatives would likely result in higher overall power prices, as the marginal cost of electricity in the U.S. is generally set by carbon intensive generation assets which burn fossil fuels such as oil, natural gas and coal. As a non-carbon emitter and a market price taker, we are positioned to benefit from these higher power prices.

Regulatory Mandates, Such as State RPS Programs, as Well as Federal Tax Incentives Including Production Tax Credits and Accelerated Tax Depreciation

        Growth in the United States' wind energy market has also been driven by state and federal legislation designed to encourage the development and deployment of renewable energy technologies. This support includes:

    Renewable Portfolio Standards.  In response to the push for cleaner power generation and more secure energy supplies, many states have enacted RPS programs. These programs either require electric utilities and other retail energy suppliers to produce or acquire a certain percentage of their annual electricity consumption from renewable power generation resources, or, as the case in New York, designate an entity to administer the central procurement of RECs for the state. Wind energy producers generate renewable energy certificates due to the environmentally beneficial attributes associated with their production of electricity.

      The number of states with RPS programs has doubled in the last six years and as of April 2008, 31 states and the District of Columbia had adopted some form of RPS program. The District of Columbia and 25 of the 31 states have mandatory RPS requirements and combined, these 25 states represent over 50% of total U.S. electrical load. A number of states, including Arizona, California, Colorado, Minnesota, Nevada, New Jersey, New Mexico, Pennsylvania and Texas, have been so successful in meeting their original RPS targets that they have revised their programs to include higher targets. Other states such as Missouri, North Dakota, South Dakota, Utah, Vermont and Virginia have adopted state goals, which set targets, not requirements, for certain percentages of total energy to be generated from renewable resources. The states that have adopted RPS or set state goals, as well as the related requirements or targets, are set forth in the following map.


U.S. RPS Programs and Goals for Renewable Energy Generation

         GRAPHIC

    Source: United States Department of Energy–Energy Efficiency and Renewable Energy, April 2008.

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    Almost every state that has implemented an RPS program will need considerable additional renewable energy capacity to meet its RPS requirements. Much of Emerging Energy Research's forecasted 50,000 MW of installed wind capacity by 2015 will be driven by current and proposed RPS targets, along with additional demand from states without renewable standards.

    Renewable Energy Certificates.  A REC is a stand-alone tradable instrument representing the attributes associated with one MWh of energy produced from a renewable energy source. These attributes typically include reduced air and water pollution, reduced greenhouse gas emissions and increased use of domestic energy sources. Many states use RECs to track and verify compliance with their RPS programs. Retail energy suppliers can meet the requirements by purchasing RECs from renewable energy generators, in addition to producing or acquiring the electricity from renewable sources. Under many RPS programs, energy providers that fail to meet RPS requirements are assessed a penalty for the shortfall, usually known as an alternative compliance payment. Because RECs can be purchased to satisfy the RPS requirements and avoid an alternative compliance payment, the amount of the alternative compliance payment effectively sets a cap on REC prices. In situations where REC supply is short, REC prices approach the alternative compliance payment, which in several states is in the $50-$59/MWh range. As a result, REC prices can rival the price of energy and RECs can represent a significant additional revenue stream for wind energy generators.

    Production Tax Credits.  The PTC provides wind energy generators with a credit against federal income taxes, annually adjusted for inflation, for a duration of ten years from the date that the wind turbine is placed into service. In 2007, the PTC was $20/MWh. Wind energy generators with insufficient taxable income to benefit from the PTC may take advantage of a variety of investment structures to monetize the tax benefits.

      The PTC was originally enacted in 1992 for windparks placed into service after December 31, 1993 and before July 1, 1999. The PTC subsequently has been extended five times, but has been allowed to lapse three times (for periods of three, six and nine months) prior to retroactive extension. Currently, the PTC is scheduled to expire on December 31, 2008 unless an extension or renewal is enacted into law.

    Accelerated Tax Depreciation.  Tax depreciation is a non-cash expense meant to approximate the loss of an asset's value over time and is generally the portion of an investment in an asset that can be deducted from taxable income in any given tax period. Current federal income tax law requires taxpayers to depreciate most tangible personal property placed in service after 1986 using the modified accelerated cost recovery system, or MACRS, under which taxpayers are entitled to use the 200% or 150% declining balance method depending on the class of property, rather than the straight line method. In addition, under MACRS, a significant portion of windpark assets is deemed to have depreciable life of five years which is substantially shorter than the 15 to 25 year depreciable lives of many non-renewable power supply assets. This shorter depreciable life and the accelerated depreciation method results in a significantly accelerated realization of tax depreciation for windparks compared to other types of power projects. Wind energy generators with insufficient taxable income to benefit from this accelerated depreciation often monetize the accelerated depreciation, along with the PTCs, through forming a limited liability company with third parties.

Improvements in Wind Energy Technology

        Wind turbine technology has improved considerably in recent years with significant increases in capacity and efficiency. Multiple types and sizes of turbines are now available to suit a wide range of wind resource characteristics and landscapes. Modern wind turbines are capable of generating high-quality, grid-compatible electricity for more than 25 years, with remote monitoring and relatively low maintenance.

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        There have been two major trends in the development of wind turbines in recent years:

    individual turbine capacity has increased dramatically over the last 25 years, with 30 kW machines that operated in 1980 giving way to the 1.5 MW machines that are standard today; and

    windpark performance has improved significantly, with turbines installed after 2005 averaging a 36% net capacity factor (the ratio of the actual output over a period of time and the output if the windpark had operated at full capacity over that time period) as compared to the 22.5% net capacity factor realized by turbines installed prior to 1998.

        Additionally, as wind energy technology has continued to improve, according to AWEA, the capital cost of wind energy generation has fallen by approximately 80% over the past 20 years.

Increasing Obstacles for the Construction of Conventional Fuel Plants

        In addition to the impediments presented by the extensive and growing environmental legislation, new power plants that use conventional fuels, such as coal and nuclear technologies, face a difficult, lengthy and expensive permitting process. Furthermore, increasing opposition from public environmental groups towards coal-fired power plants, coupled with rising construction costs, contributed to the cancellation of many planned coal plants in 2007. According to Resource Media, a public relations firm representing environmental groups in the western United States, the construction of 31 coal-fired plants totaling 24,250 MW was canceled or delayed in 2007. As a result, despite increasing gross margins, only about 2,000 MW of net new capacity from coal and nuclear plants was brought online between 2003 and 2006. Additionally, in October 2007, the Kansas Department of Health and Environment became the first government agency in the United States to cite carbon dioxide emissions as the reason for rejecting an air permit for a proposed coal-fired electricity generating plant, saying that the greenhouse gas threatens public health and the environment. Traditional energy developers and utilities are likely to face similar permitting and restricted supply issues in the future. As a result, alternative energy sources such as wind will need to be developed to meet increasing electricity demand and will be able to capitalize on the resulting higher energy prices.

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Abundant Wind Resources in Attractive Energy Markets within the United States

        The potential for future growth in the U.S. wind energy market is supported by the large land area available for turbine installations and the availability of significant wind resources. According to the AWEA, annual average wind speeds of 11 miles per hour or greater are required for grid-connected windparks. As shown in the map below, a large portion of the United States exhibits wind speeds sufficient for windpark development.

GRAPHIC

Source: United States Department of Energy—Pacific Northwest National Laboratory, October 1986.

Wind Energy Fundamentals

        The term "wind energy" refers to the process used to generate electricity through wind turbines. The turbines convert wind's kinetic energy into electrical power by capturing it with a three blade rotor mounted on a nacelle that houses a gearbox and generator. When the wind blows, the combination of the lift and drag of the air pressure on the blades spins the blades and rotor, which turns a shaft through the gearbox and generator to create electricity.

        Wind turbines are typically grouped together in what are often referred to as "windparks." Electricity from each wind turbine travels down a cable inside its tower to a collection point in the windpark and is then transmitted to a substation for voltage step-up and delivery into the electric utility transmission network, or "grid." Today's wind turbines can efficiently generate electricity when the wind speed is between 11 and 55 miles per hour.

        A key factor in the success of any windpark is the profile and predictability of the wind resources at the site. Extensive studies of historical weather and wind patterns have been performed across North America and many resources, in the forms of charts, graphs and maps, are available to wind developers. The most attractive windpark sites offer a combination of land accessibility, power transmission, proximity to construction resources and strong and dependable winds.

        When wind energy developers identify promising sites, they perform detailed studies to provide greater certainty with respect to the long-term wind characteristics at the site and to identify the most effective turbine siting strategy. The long-term annual output of a windpark is assessed through the use of on-site wind data, publicly available reference data and sophisticated software. Wind speeds are

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estimated in great detail for specific months, days or even hours, and are then correlated to turbine manufacturers' specifications to identify the most efficient turbine for the site. Additional calculations and adjustments for turbine availability (which is principally affected by planned and unplanned maintenance events), wake effects (wind depletion caused by turbines sited upwind), blade soiling and icing and other factors are made to arrive at an estimate of net expected annual kilowatt hour electricity production at the site.

Sources of Revenue for Wind Generators

        Wind energy generators primarily derive revenue from three sources:

    Energy sales.  Energy sales are derived from the sale of energy into a wholesale market or to a specific customer, such as a utility or power marketer;

    REC sales.  In many states, conventional energy producers are required either to produce a certain percentage of their energy from renewable sources or to purchase RECs from renewable energy producers. RECs represent the environmental attributes associated with electricity from renewable sources. RECs are a tradable instrument that can be sold separately from the electricity produced by a renewable generation source, thereby providing an additional revenue stream; and

    Capacity sales.  In some, but not all states in which we are operating or developing windparks, payments are made to energy generators, including windparks, as a market incentive to promote the development and continued operation of capacity sufficient to meet regional load and reserve requirements. Market systems have been established to ensure that generators receive these payments based on their availability to generate electricity. Payments are generally allocated to windparks based on the previous year's capacity for the super-peak hours during winter and summer qualifying periods.

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BUSINESS

Company Overview

        We are a rapidly growing wind energy company operating 282 megawatts, or MW, of electrical generating capacity with more than 950 MW of additional capacity that we expect to commence operations during 2008 and 2009. We are focused on developing, financing, constructing, owning and operating windparks in attractive energy markets in the United States. Our strategy is to grow our business principally through organic development in regions with deregulated power markets, acceptable wind resources and favorable legislative and economic incentives such as renewable portfolio standard, or RPS, programs and active renewable energy certificate, or REC, markets. Through RPS programs and REC markets, we are able to monetize the environmental attributes associated with our power, in addition to generating revenue from the actual power we produce. Operating in these attractive deregulated energy markets also enables us to execute our energy hedging strategy, which helps stabilize our revenues while allowing us to benefit from future increases in energy prices.

        We were founded in August 2004 and commenced operations of our first windparks in March 2008. We have grown into a fully integrated wind energy company with 152 employees, with the capability to develop, finance, construct, own and operate our windparks. We utilize our understanding of the commodity markets to site our windparks in attractive regions and to monetize the output of our projects effectively. Our engineering and construction team has the ability to either act as general contractor on a project, coordinating with third-party construction contractors, or to engage a third-party in the general contractor or construction management role. We make these decisions based on economic benefit to us. We believe that this two-fold construction strategy differentiates us from other independent U.S. wind energy companies, which typically rely only upon third-party general contractors. Similarly, while we generally intend to operate and maintain our windparks ourselves, we retain the flexibility to use third-party service providers. This also differentiates us from other independent U.S. wind energy companies.

        In addition to our current capacity of 282 MW, we have begun construction of additional windparks in New York and Texas that we expect will provide 465 MW of capacity in 2008. We plan to grow our capacity significantly over the next several years. By the end of 2012, we expect to have approximately 3,850 MW of capacity as we further expand into attractive wind energy markets in Maine, Michigan, Minnesota, New Hampshire, Vermont and Wyoming. In addition, we continuously identify and evaluate new windparks as part of our core business strategy. Windpark project development has been and will continue to be one of our core strengths and areas of focus. Based on our historical success in identifying new windpark projects, we expect that these project development efforts will result in an additional 4,000 MW development pipeline of windparks, which could be constructed after 2012.

        We also maintain strong relationships with major turbine suppliers, who we expect will provide the turbines required for our expanding windpark portfolio. We have secured access to the turbines needed for our projects slated for construction through 2009. We believe that the strong track record of our experienced management team, the expertise of our project development team dedicated to sourcing new opportunities, our integrated business model and our turbine supply relationships provide us with the knowledge and resources necessary to rapidly grow our windpark portfolio.

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Growth in Our Windpark Portfolio

         GRAPHIC

(1)
Capacity represents the maximum output, measured in megawatts, that an individual wind turbine generator is designed to produce. The capacity of a windpark equals the capacity of the generators multiplied by the number of generators included in the windparks.

Our Windpark Portfolio

        Our operational project portfolio is located in New York and consists of three windparks: Bliss, Clinton and Ellenburg. We refer to these windparks as our "Initial New York Windparks." Additionally, we have 465 MW of projects currently in construction in New York at our Altona, Bellmont, Chateaugay and Wethersfield windparks and in Texas at phase I of our Great Plains windpark, all of which we expect to commence operations in the fourth quarter of 2008. We also have 1,205 MW of projects currently in development, which we expect to commence operations in 2009 and 2010 and an additional 1,900 MW of projects in development, which we expect to commence operations during 2011 and 2012. Substantially all of these identified projects are located in attractive deregulated energy markets and in areas that we have determined have acceptable wind resources. For projects that we expect will commence operations between 2008 and 2010, we have secured control of the land necessary to construct our windparks, identified transmission interconnection and established relationships in the local communities. In addition, we have secured the turbines needed to support our windparks slated for construction through 2009.

        We focus on certain key energy market characteristics when identifying projects to add to our portfolio. Potential projects are then evaluated against our investment criteria to determine their attractiveness. The energy market characteristics are:

    Liquid Energy Markets.  We seek to locate our projects within established, deregulated energy markets, with price levels and market liquidity that provide us with attractive returns and greater hedging flexibility. Often these attractive markets are located in regions where gas fired electricity generation sets the market price the majority of the time, or where tight supply/demand balances result in attractive market clearing prices, and where an independent system operator administers the energy markets, creating price visibility and physical liquidity.

    Active REC Markets.  We also look at whether the state or region in which the potential site will be located has an RPS program that presents an opportunity to generate additional revenues through the sale of RECs. These credits represent the monetization of wind energy's environmental benefits and are generally purchased by electric utilities or other retail energy suppliers, or procured by a state agency as mandated by state law (as is the case in New York).

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    Available Capacity Markets.  When we consider whether to site a windpark in a particular location, we also evaluate the opportunity for receiving payments in the capacity market. In certain markets, capacity payments are paid to generators for having operating generation facilities capable of producing energy within the applicable power pools and provide additional revenues to enhance the economics of our projects.

        In addition to exhibiting key energy market characteristics, our projects must also meet a stringent set of development criteria and are regularly evaluated to ensure that key milestones are being met. These development criteria are:

    Land Control.  For us to consider this milestone completed, we must have obtained easements or other written rights of access to a majority of the land that we believe is necessary for the construction and operation of the windpark.

    Transmission Interconnection Study.  For us to consider this milestone completed, we must have identified a point of interconnection to the transmission system, obtained a queue position and commenced or completed a system impact study. A system impact study and its approval by the relevant transmission system operator is a prerequisite to the design and construction of the facilities that will interconnect the windpark with the transmission system.

    Meteorological Data.  For us to consider this milestone completed, we must have reviewed existing wind information, installed one or more measurement towers on site, developed a site plan, evaluated all of these data and made an estimate of project energy output that we believe is acceptable for a viable windpark.

    Turbine Supply Secured.  For us to consider this milestone completed, we must have entered into a written agreement that secures the turbines necessary for the windpark. Typically, turbine suppliers will only contract for turbines approximately two years in advance of their scheduled delivery date.

    Environmental Impact Study and Permitting.  In most of the states where we develop windparks, completion of an environmental impact study, or EIS, is a prerequisite to obtaining the key permits necessary for the construction and operation of our project. We generally initiate the studies needed for an EIS approximately 18 months prior to the anticipated construction start date and receive the material permits shortly before financing close and start of construction. For us to consider this milestone completed, we will have either finished an EIS or received the material permits for the construction and operation of our windpark.

        In our view, when all of these milestones and development criteria have been met, it is likely that the windpark will be able to meet the conditions necessary to obtain project financing and ultimately be constructed and commence operations. This development process typically spans two to three years.

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        The following chart sets forth our windparks in operation, in-construction and in-development and indicates the market characteristics that exist and the key development criteria that have been met for each windpark:


Windpark Characteristics

 
  Location and Capacity
  Market Characteristics
  Development Criteria
 
  State
  ISO
  Capacity (MW)
  Liquid
Energy
Market

  REC
Market

  Capacity
Market

  Land
Control

  Transmission
Study
Commenced
or Completed

  Met Data
Available

  Turbines
Secured

  EIS /
Permits

Initial New York Windparks                                            
Bliss   NY   NYISO   100.5   ü   ü   ü                    
Clinton   NY   NYISO   100.5   ü   ü   ü   Operational Windparks
Ellenburg   NY   NYISO   81.0   ü   ü   ü                    
           
                               
  Capacity Subtotal           282.0                                
           
                               
2008 Windparks                                            
Altona   NY   NYISO   97.5   ü   ü   ü   ü   ü   ü   ü   ü
Bellmont   NY   NYISO   21.0   ü   ü   ü   ü   ü   ü   ü   ü
Chateaugay   NY   NYISO   106.5   ü   ü   ü   ü   ü   ü   ü   ü
Wethersfield   NY   NYISO   126.0   ü   ü   ü   ü   ü   ü   ü   ü
Great Plains I   TX   SPP   114.0   ü   ü     ü   ü   ü   ü   ü
           
                               
  Capacity Subtotal           465.0                                
           
                               
2009 Windparks                                            
Ball Hill/Villanova   NY   NYISO   100.5   ü   ü   ü   ü   ü   ü   ü  
Centerville/Rushford   NY   NYISO   100.5   ü   ü   ü   ü   ü   ü   ü  
Chateaugay II   NY   NYISO   19.5   ü   ü   ü   ü   ü   ü   ü  
Great Plains II   TX   SPP   126.0   ü   ü     ü   ü   ü   ü   ü
Mitchell County I (Phase I)   TX   ERCOT   153.0   ü   ü     ü   ü   ü   ü  
           
                               
  Capacity Subtotal           499.5                                
           
                               
2010 Windparks                                            
Burke   NY   NYISO   60.0   ü   ü   ü   ü   ü   ü    
Farmersville   NY   NYISO   100.5   ü   ü   ü       ü    
Mitchell County I (Phase II)   TX   ERCOT   147.0   ü   ü     ü   ü   ü    
Mitchell County II   TX   ERCOT   150.0   ü   ü     ü   ü   ü    
Grandpa's Knob   VT   ISONE   72.0   ü   ü   ü   ü     ü    
Granite Reliable   NH   ISONE   75.0   ü   ü   ü     ü   ü    
Flat Hill I   MN   MISO   100.5   ü   ü     ü     ü    
           
                               
  Expected Capacity Subtotal           705.0                                
           
                               
  Expected Total Capacity through 2010           1,951.5                                
           
                               
2011/2012 Windparks                                            
Expansion of existing windparks           800.0                                
New windparks in existing states           550.0                                
Windparks in new states           550.0                                
           
                               
  Estimated Capacity Subtotal           1,900.0                                
           
                               
  Expected Total Capacity through 2012           3,851.5                                
           
                               

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Projects in Development for 2011-2012

        We have identified 1,900 MW of windpark projects that we expect will commence operations in 2011 and 2012. Of this amount, we expect a geographic distribution of projects as shown below:

State

  Estimated
Capacity (MW)

Maine   50
Michigan   400
Minnesota   200
New York   175
Texas   800
Vermont   175
Wyoming   100
   
  Total   1,900
   

        The windparks in Minnesota, New York, Texas and Vermont will represent additional operations or expansions of the windparks that we expect to have in operation in these states by 2010. The windparks in Maine, Michigan and Wyoming represent new states being added to our project portfolio, although we have significant experience with the energy markets and regulatory environment in Michigan as a result of our prior development activities in that state.

        For the majority of these projects, we have secured a portion of the land necessary to place our turbines and have analyzed the characteristics of the applicable energy, capacity and REC markets. We have also performed preliminary wind analysis, started discussions concerning the interconnection process and initiated a dialogue with the local communities. The development of these projects, however, is still subject to many of the risks described in "Risk Factors," which may cause delays or in some cases, termination of the project.

        Our project development group continuously explores opportunities to add new windparks to our portfolio. We expect that these project development efforts will result in a 4,000 MW development pipeline of projects which could be constructed after 2012, adding to the 3,850 MW portfolio that we expect to have in operation at the end of 2012.

Our Competitive Strengths

        We believe that the following strengths position us to profitably grow our windpark portfolio in the rapidly developing U.S. wind energy market:

    High-quality portfolio of operating, in-construction and in-development windparks located in attractive U.S. energy markets;

    Fully integrated in-house capabilities to develop, finance, construct, own and operate windparks and to support the continuing growth of our portfolio;

    Experienced and proven management team with an average of more than 20 years of experience with complex power projects;

    Strong relationships with major turbine suppliers and all of the turbines secured to support our projects slated for construction through 2009; and

    Substantial local presence and community stakeholder involvement in the markets in which we are active.

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High-quality portfolio of operating, in-construction and in-development windparks located in attractive U.S. energy markets

        We believe that our strategically located portfolio of operating, in-construction and in-development windparks ideally positions us within the rapidly growing U.S. wind energy market. We currently have projects representing 282 MW of capacity in operation in New York. Later in 2008, we expect to commence operations in Texas and bring further New York projects online, representing an aggregate addition of 465 MW of capacity. In 2009, we expect to bring further New York and Texas projects online, representing an aggregate addition of 500 MW of capacity. In 2010, we expect to commence operations in New England (New Hampshire and Vermont) and Minnesota, as well as bring further New York and Texas projects online, representing an aggregate addition of 705 MW of capacity. By the end of 2012, we expect to have operational projects representing 3,850 MW of capacity in Maine, Michigan, Minnesota, New Hampshire, New York, Texas, Vermont and Wyoming. As indicated in the discussion of our windpark portfolio above, we have already completed substantial milestones for our projects targeted for completion through 2010.

        In addition, we believe that our development portfolio will give us significant scale across a geographically diverse national footprint. We carefully select our project sites to ensure that they are in regions characterized by acceptable wind resources, high power prices in deregulated energy markets and favorable renewable energy policies. We believe our management's experience in developing windparks in new markets and adding projects in our existing markets will enable us to continue to successfully expand our development portfolio. Additionally, we believe our management's understanding of deregulated energy markets enables us to maximize the value of our development portfolio. We devote considerable resources to structuring and assembling our project portfolio to achieve disciplined growth in the regions that we believe offer the most economically attractive returns.

Fully integrated in-house capabilities to develop, finance, construct, own and operate windparks and to support the continuing growth of our portfolio

        Our fully integrated, cross-functional organizational structure enables us to develop, finance, construct, own and operate each of our projects with a long-term ownership perspective. Our commodities and risk management team works closely with our developers and meteorological team on identifying regions for optimal project development. Collaboration among the developers, engineers and managers on each of our projects allows us to transition from one stage to the next and to regularly identify process and technical improvements over the life-cycle of each project. This integrated project management strategy enables us to continuously improve the development timing, cost and capital structure and revenue optimization of projects across our portfolio. Additionally, our management team has extensive project finance and commodity hedging expertise, allowing us to optimize our capital structure and reduce the impact of spot market price volatility.

        At our windparks, we have staff from the development, legal, construction, operations and asset management disciplines. Our fully integrated approach can provide us significant operational flexibility, a high level of quality control and the ability to manage costs and make decisions quickly and efficiently. For example:

    during the construction period of the Initial New York Windparks, when we had to change the path of a collection line (a cable that connects the turbines to the substation), our development team worked with the affected landowners, while the onsite environmental team assessed any potential impact on existing permits and the construction team gave real-time input as to the feasibility of alternate routes;

    our operators were involved in the commissioning of the turbines at our Initial New York Windparks and will operate them throughout their life, including during the initial warranty period provided by GE under the turbine supply agreements. This familiarity with our assets has

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      enabled the operating team to develop a tailored preventative maintenance program and smoothly integrate with the asset management and commodities groups to maximize the revenues from these windparks; and

    at our Initial New York Windparks, we acted as the general contractor for the construction process and we have served as the operator since the Initial New York Windparks were commissioned. We believe that these efforts have enabled us to save the mark-up that we would have incurred if third parties had provided these services. These arrangements also gave us significantly more flexibility to make changes in the construction scope and timetable (which may have resulted in penalties if we had used a third-party general contractor).

Experienced management team with an average of more than 20 years of experience with complex power projects

        Our management team has extensive knowledge of every aspect of the development, financing, construction and operation of windparks, as well as many years of experience in traditional independent electricity generation. Our senior management has an average of over 20 years of experience and involvement in bringing domestic and international power projects online, from initial development through financing to ongoing operations and maintenance, and have devoted their careers to the power and wind industries. They have formerly held leadership positions at many national and international power companies, including GE, FPL Energy, Public Service Enterprise Group, U.S. Generating Company, Kenetech, Enron, Vestas American Wind Technology and Sempra Energy. Additionally, members of our finance team have held leadership positions raising project financing for or providing investment banking services to the power sector at JPMorgan Chase, HSBC Securities, Wachovia Securities and Société Générale.

        We also have significant experience in our E&C and O&M functions. Our senior construction team includes personnel who have supervised the design and construction of power facilities in excess of 5,400 MW over the last ten years. Additionally, our senior operations team has been responsible for the operation of windparks in excess of 2,100 MW over the last ten years.

Strong relationships with major turbine suppliers and all of the turbines secured to support our projects slated for construction through 2009

        Access to wind turbines is a crucial factor in the ability of wind energy developers to build out their pipeline of projects. As a result of the rapid growth in the wind energy industry, developers are facing increased competition in procuring wind turbines. In order to address this issue, we have built strong relationships with major turbine suppliers and have successfully secured all of the turbines needed to support our projects slated for construction through 2009. Our exclusive turbine supplier to date has been General Electric. With over 6,500 GE 1.5 MW wind turbines installed worldwide, GE turbines have an established track record and a solid history of reliability. Each of our operating technicians undergoes an intense training program at the GE Wind Training Center to standardize maintenance practices and minimize variability of our maintenance procedures among our windparks. In addition to GE, we maintain an active dialogue with another turbine supplier, as well as with the suppliers of spare parts for our turbines. As we continue to grow our portfolio, we believe that our strong relationships, scale and purchasing power will enable us to continue to secure the turbines and related spare parts necessary to support our growth on favorable terms with respect to payment, pricing and flexibility.

Substantial local presence and community stakeholder involvement in the markets in which we are active

        We maintain permanently staffed project offices in Altona, Arcade, Bliss, Churubusco and Fredonia, New York; Austin and Hitchland, Texas; Lancaster, New Hampshire; Ubly, Michigan and

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Rutland, Vermont. By maintaining these offices and becoming involved in local community affairs, we develop a meaningful local presence, which we believe provides us with a significant advantage when navigating the local permitting processes and helps to enlist the support of the local communities for our projects.

        When we identify a new project, our developers move to that local area and integrate themselves into the community by attending public meetings. In this way, the local community recognizes that we are committed to making positive contributions to the area. Additionally, our involvement in the area helps to generate support from key local stakeholders such as significant landowners, local political bodies and business leaders. We believe that our community based approach has enabled us to secure approvals and support for our projects in regions that have historically voiced meaningful opposition and has given us a significant advantage over competitors who are not as active in the local communities.

Business Growth Strategy

        We intend to implement the following strategies to profitably grow our windpark portfolio in the rapidly developing U.S. wind energy market:

    Focus development of wind capacity in attractive deregulated and geographically diverse energy markets;

    Enter regional markets in scale, primarily through organic development;

    Extract the efficiency benefits of our fully integrated business model;

    Manage commodity price risk while retaining potential energy value;

    Utilize debt and tax equity finance structures;

    Create relationships as a community stakeholder; and

    Attract, train and retain top talent.

Focus development of wind capacity in attractive deregulated and geographically diverse energy markets

        We seek to develop windparks within geographically diverse, established and deregulated energy markets that have attractive energy pricing, strong RPS programs and, in many cases, capacity payments. In implementing this strategy, we have initially focused on New York, Texas, New England and a limited number of other states, which meet this criteria. We intend to expand our operating wind generation portfolio by entering into new markets, while simultaneously adding projects adjacent to our existing projects. We believe that this carefully designed expansion plan will allow us to effectively leverage our existing resources while seeking development opportunities in new markets.

        We seek to develop our projects in markets with attractive pricing dynamics, as indicated by tightening supply and low or declining reserve margins. A reserve margin is a measure (expressed as a percentage) of the available capacity that is expected to exceed forecasted peak demand across a region. A decline in reserve margins indicates a reduction in the supply of capacity relative to peak demand. This increasing scarcity of capacity and transmission constraints is likely to put upward pressure on both energy prices and capacity payments.

        Regulatory or administrative bodies typically set targets or requirements for reserve margins. For instance, the New York State Reliability Council set reserve margins for New York at 16.5% and ERCOT, the system operator in Texas, set a minimum reserve margin of 12.5%. Additionally, according to the Energy Information Administration, the vast majority of regions in which we intend to grow our project portfolio have experienced declining reserve margins since 2004. From 2004 to 2006, the average reserve margin in the contiguous United States declined from 26% to 19%, with continued

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declines forecasted through 2011. The following table summarizes the significant characteristics of the energy markets in which we intend to develop and operate windparks.


Energy Market Characteristics

State

  2007 Average
Retail
Electricity
Price
(¢/kWh)(1)

  RPS Energy Target
  2007 REC Prices
  Separate Capacity Market
  2006 Capacity Price ($/kW-mo.)
  Actual 2006 Reserve Margin
Michigan   8.60¢   None   Not available   No   Not applicable   18%(7)

Minnesota

 

7.36¢

 

25% by 2025

 

Not available

 

No

 

Not applicable

 

18%(7)

Maine

 

13.26¢

 

30% by 2000 (10% by 2017 for new renewable energy sources)

 

$54(2)

 

Yes

 

$3.05(5)

 

10%(8)

New Hampshire

 

13.96¢

 

23.8% in 2025

 

$54(2)

 

Yes

 

$3.05(5)

 

10%(8)

Vermont

 

11.99¢

 

Renewable energy meets load
growth by 2012; 20% by 2017

 

$54(2)

 

Yes

 

$3.05(5)

 

10%(8)

New York

 

15.35¢

 

24% by 2013

 

$15(3)

 

Yes

 

$2.61(6)

 

17%(9)

Texas

 

10.27¢

 

5,880 MW by 2015

 

$4(4)

 

No

 

Not applicable

 

14%(10)

Wyoming

 

5.27¢

 

None

 

Not available

 

No

 

Not applicable

 

24%(11)

Source: Average Retail Electricity Prices from EIA; New York capacity prices from ESAI Capacity Watch, March 2008; New England capacity prices from FERC; RPS targets from the Database of State Incentives for Renewables & Efficiency, April 2008; REC prices from Evolution Markets Inc. 2006 reserve margins from the FERC.

(1)
2007 annual average retail electricity prices.
(2)
2007 Massachusetts average bilateral transaction price as reported by Evolution Markets Inc.
(3)
2007 New York average procurement price per NYSERDA press release, dated April 19, 2007.
(4)
2007 Texas average bilateral transaction price as reported by Evolution Markets Inc.
(5)
Represents the ISO-NE forward capacity market transition payment with the value fixed from December 2006 through May 2008; the last UCAP auction held in the ISO-NE was in October 2006.
(6)
Represents the New York Rest of State 2007 monthly average spot market ICAP price.
(7)
Summer peaking reserve margin for MISO.
(8)
Summer peaking reserve margin for ISO-NE.
(9)
Summer peaking reserve margin for NY-ISO.
(10)
Summer peaking reserve margin for SPP and ERCOT (14% in 2007 for ERCOT)
(11)
Summer peaking reserve margin for the Southwest for 2005.

Enter regional markets in scale, primarily through organic development

        Upon entering a market, we seek to become a leading wind energy operator and an influential voice within the region. We believe that our large scale projects will enable us to take full advantage of the benefits of our local presence and spread our fixed infrastructure and operating costs over a large number of turbines. While we may opportunistically acquire existing or partially developed windparks, we expect to grow our portfolio primarily through organic development, which means developing each project in-house, from initial site selection through construction and operation. We believe that this approach will allow us to execute a deliberate expansion plan for growth without relying on acquisitions. We believe that our organic development model is generally preferable to acquiring projects because of the time and risk related to finalizing development on a third party's project and the premium these opportunities attract in the current competitive market.

Extract the efficiency benefits of our fully integrated business model

        We seek to maximize project efficiency and reduce costs by taking advantage of our in-house capabilities in development, financing, construction and operations. For example, in the construction phase, we believe our ability to choose between using outside providers or taking advantage of our in-house capability to act as a general contractor gives us significant flexibility. Additionally, we will maintain a central warehouse of spare parts, which we believe will result in significant benefits,

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including increased operational flexibility as we will not have to delay maintenance as a result of waiting for an item with a long-lead time to arrive. As our asset base grows, we believe we will achieve further cost reductions due to economies of scale in maintaining our windparks and purchasing components.

Manage commodity price risk while retaining potential energy value

        We have implemented and expect to continue to implement financial hedges with respect to the majority of the energy we produce. The effect of these hedges is to help stabilize our revenue stream by reducing the impact of regional energy spot market price volatility. We forgo some of the potential benefit of increases in future energy prices by receiving the fixed price from the hedge counterparty rather than the floating price we would otherwise receive from the market. However, our hedging arrangements are designed to protect us against the risk of decreases in energy rates. This benefits both us and our lenders by strengthening our ability to provide sufficient debt service coverage and as a result greatly enhances our ability to obtain debt financing on attractive terms. We can still benefit from future increases in energy prices through the unhedged portion of our energy production both in the early years of the project's life (as the actual energy volume generated by the projects is expected to be greater, on average, than the hedged volume) and in the time after the hedging arrangement expires. Furthermore, our strategy of entering into hedges around the time of the closing of financing for a windpark as opposed to pursuing power purchase agreements, or PPAs, allows us to potentially benefit from future energy price movements and avoid the cost and price competition involved in bidding on PPAs. Additionally, our current arrangements incorporate the concept of a "tracking account" that effectively defers some or all of the risks associated with the variability in our energy production volume until later in the project's operational life when the project debt has been significantly amortized. The tracking account essentially transfers the credit risk of this deferral to the hedge counterparty. For further discussion of our hedging strategy, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Revenues."

Utilize debt and tax equity finance structures

        In our selection of the various financing alternatives generally available to wind energy developers, we seek to maximize the rate of return on our project investments and monetize the tax benefits that we currently cannot utilize due to our lack of taxable income. We attempt to finance substantially all of our turbine purchases with debt secured primarily by the turbines themselves in order to increase our flexibility with respect to the specific projects in which turbines will be placed. We also use construction and project debt financing to minimize recourse against the issuer while optimizing our use of third-party capital. Finally, we will use tax equity financing arrangements in order to monetize the value generated by PTCs and accelerated tax depreciation that are available to us as a wind energy generator. We will be able to enter into these arrangements at a cost of capital that reflects the tax equity investor's ability to utilize these tax benefits. Until we have significant taxable income, we intend to continue financing our windparks with tax equity financing structures so long as tax incentives and tax equity investors remain available.

Create relationships as a community stakeholder

        As part of our development strategy, we aim to create strong community relationships that we believe are critical to securing the land necessary for our windparks. Our team works closely with the landowners who will host the windpark to ensure that they fully understand the impact of having turbines on their property. Throughout the process, we assess and monitor the landowners' and broader community's receptiveness and willingness to host a windpark, while providing a program to educate the communities on the benefits of having a windpark in their area. This proactive involvement in the community also enables us to submit permit applications that are tailored to address local concerns.

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Attract, train and retain top talent

        As we continue to grow our business and add new windparks to our portfolio, we will need to attract, train and retain additional employees. We believe that our collaborative culture, fully integrated management model and internal human resource development abilities are critical to attracting new and experienced talent and retaining key team members, such as our engineers, developers and meteorology experts. We provide extensive training, and we believe that we offer attractive employment opportunities in the markets in which we operate. In addition, as part of our retention strategy, we will be issuing equity incentive awards to certain key members of our team in connection with this offering.

Organization of Our Business

        Our business is organized around the projects in our portfolio. There are four key functional stages associated with developing and operating a windpark: (i) development, (ii) financing and commodity risk management, (iii) engineering and construction and (iv) operations and maintenance.

GRAPHIC

Development

    Site Selection, Land Control and Permitting

        Our development professionals select areas for development, first by evaluating regional energy, REC and capacity market characteristics, wind resources and land use patterns, and then by screening specific candidate sites for transmission availability, interconnection options, environmental sensitivity, local community receptivity and the potential for organized opposition. In performing this screening, we use both advanced technology and human capital to fully investigate and understand the factors that will affect our ability to permit and develop a project with attractive financial potential.

        Once a suitable site is located, the development phase begins with the identification, selection and securing of the land area required for the windpark. Developers work one-on-one with the landowner or landowners to obtain access and control over the real estate needed to support the windpark and transmission facilities. We memorialize our agreements with landowners through easements and leasing arrangements, which generally provide for a nominal rent payment over the remaining development

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and construction periods and increased payments when the windpark is operational. The majority of those payments are based on the performance of the windpark once operational.

        Early in the development cycle, prior to the finalization of a windpark's design, we also begin the environmental impact evaluation process. This entails extensive field work to identify environmental concerns that may impact the issuance of a permit for construction and project layout, such as the presence of endangered species, valuable wetlands or protected scenic views.

        At all the stages of the development process, we believe that it is important for members of our development team to live in and become active members of the communities in which they work. This approach gives our staff the opportunity to develop relationships with members of the community and educate them about the benefits of our projects, which we believe reduces the chance of community opposition. Strong relationships with community members also enable our developers to identify local issues of concern and address these in the project designs. The local team also works closely with our environmental and legal groups to ensure that the projects can be efficiently permitted. In addition, our public affairs group conducts community outreach in the local area near the proposed windpark and helps to communicate information about wind energy, windparks and our long-term commitment to the host communities.

        Once a windpark is operational, we continue to maintain a local presence at the site to retain the support of the community and address concerns in a timely fashion. With a long-term vision for development, we understand the importance of maintaining a continuous dialogue with all stakeholders who may be involved in our current and future projects.

    Wind/Meteorological Analysis

        A key factor in the success of any windpark is the profile and predictability of the wind resources at the site. Extensive studies of historical weather and wind patterns have been performed across North America and many resources, in the forms of charts, graphs and maps, are available to wind developers. The most attractive windpark sites offer a combination of land accessibility, power transmission, proximity to construction resources and favorable and dependable winds.

        When wind energy developers identify promising sites, they perform detailed studies to provide greater certainty with respect to the long-term wind characteristics at the site and to identify the most effective turbine siting strategy. The long-term annual output of a windpark is assessed through the use of on-site wind data, publicly available reference data and sophisticated software. Wind speeds are estimated in great detail for specific months, including intra-day variations, and are then correlated to turbine manufacturers' specifications to identify the most efficient turbine for the site. Today's wind turbines can efficiently generate electricity when the wind speed is between 11 and 55 miles per hour. Additional calculations and adjustments to determine turbine availability (which is principally affected by planned and unplanned maintenance events), wake effects (wind depletion caused by turbines sited upwind), blade soiling and icing and other factors are made to arrive at an estimate of the net capacity factor. A windpark's net capacity factor is the percentage represented by the energy output in MWh measured at the revenue meter over a period of time, divided by the product of the capacity of the windpark in MW multiplied by the number of hours in the measurement period. For example, if a 100 MW windpark generates 306,600 MWh in one year (8,760 hours), the net capacity factor equals 35%.

        We have an in-house wind technologies team, including three professionals with graduate degrees in meteorology who provide support at each stage of the development and construction processes and during ongoing operations. Our in-house scientists work closely with several leading subcontractors to develop statistical modeling, data quality assurance and sophisticated programs to measure wind characteristics at turbine hub-height and above. We also research wind characteristics over the entire wind turbine rotor disk (the diameter of the spinning blades). Finally, our meteorological team

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investigates climate variability. This research often leads to improvements in our routine wind energy assessment program.

        Our wind program starts with prospecting for windy sites over a wide area by using public wind maps or maps that we commission. These maps are generated with sophisticated statistical models, which use global climatic data and detailed local terrain characteristics, and identify the most attractive land for a windpark in a specific region. Once our development team secures access to a portion of the targeted land, we begin a field program by establishing a long-term reference 60-meter instrumented tower. This field test is followed by the installation of numerous additional towers that probe the wind resources across the entire prospective site plan. Depending on site specific issues, we may do additional studies with hub-height fixed towers or SODAR, which is a remote sensing technology that measures winds up to a height of 200 meters without the need for a tower.

        Our in-house experts also use statistical models for siting wind turbines within a windpark in conjunction with our field environmental team. Together, these teams determine areas where wind turbines cannot be located due to environmental, zoning, turbine-related or other restrictions. This modeling enables us to adjust site plans very quickly, which substantially shortens our development and engineering cycles. We and our consultants prepare estimates of the long-term energy production capability of each project, as well as the short-term energy variability characteristics, while adhering to a rigorous quality assurance program to ensure the quality of the wind data required by our commodity hedge counterparties and lenders. These energy estimates are continuously improved as data is collected. Prior to obtaining project financing, we submit our data and analyses for review by independent wind consultants.

    Transmission Interconnection

        Transmission interconnection is one of the key elements of windpark development as it ensures connectivity and access to power markets. We seek to identify the most cost effective point of interconnection to the regional power grid while not compromising the reliability and security of the transmission network or market access. The first step in the interconnection process is filing an interconnection application with the regional independent system operator, or RTO. The ISO then coordinates with us to complete three consecutive studies: a feasibility study, a system impact study and a facilities study. The objective of the feasibility study is to determine whether there is adequate transmission resource sufficiently close to the proposed windpark. The goal of the system impact study is to evaluate the impact of the proposed windpark on the transmission network, while the facilities study determines the required physical interconnection facilities and any network upgrades along with the costs associated with such requirements. In aggregate, these studies generally take nine to twelve months to complete; however, this timeline can change from ISO to ISO, depending on the number of proposed projects in the ISO's interconnection applications queue. In addition, if we fail to meet the study process milestones set by the rules, we may lose our position in the transmission planning queue, with the possible result that our windparks may be required to restart the study process.

        At the conclusion and acceptance of the facilities study, we negotiate an interconnection agreement with the ISO and the transmission owner. This agreement defines the cost allocation and schedule for interconnection and upgrades as well as outlines the facilities' ownership and operation. In certain cases, where an agreement for an interconnection agreement with the transmission owner and or/operator is not reached after 60 days of negotiation, we can request that the transmission owner and/or operator submit an unexecuted interconnection agreement to FERC. The transmission interconnection process, from the start of the studies through the filing of the interconnection agreement, can take up to two years or more to complete.

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Financing and Commodities Risk Management

        We have established two groups responsible for executing our windpark financing and commodity risk management strategies. Our financing and commodities risk management groups work closely together to ensure that our projects can be economically financed in a timely manner and to manage our exposure to and maximize our potential upside from volatility in the energy markets. These two groups are charged with implementing and managing the financing structures that we use to fund our windparks' development, construction and operations, executing our electricity hedging strategy and managing our energy, capacity and REC sales.

    Turbine Financing

        We fund the cash required to pay for turbines purchased under our turbine supply agreements through borrowings by certain of our subsidiaries under turbine credit facilities. We currently have in place a first lien revolving turbine credit facility and a second lien turbine credit facility. These facilities allow us to finance between 60% and 100% of our turbine purchases with debt. These facilities are secured by, among other things, turbines not yet transferred to a project subsidiary for use in a particular windpark. By not transferring turbines specifically to the owners of our windparks and not pledging all general project assets as collateral, we maintain the ability to purchase turbines in advance of project development and construction, which provides us with a large degree of flexibility regarding the specific windparks in which turbines will be ultimately placed. For a further discussion of the first and second lien turbine credit facilities, see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources" and "Description of Certain Financing Arrangements—Senior Secured Turbine Credit Facilities."

    Commodity Risk Management

        We view the understanding of, and participation in, the energy commodity markets as an integral component required for success in the U.S. wind energy industry. Our commodity risk management team designs and implements energy hedging structures to help manage energy commodity price risk and production volume fluctuation risk. Our energy hedging arrangements enable us to effectively transfer energy price risk to our hedging counterparty with respect to a portion of the energy generated at our windparks. These arrangements protect us from volatility in the energy markets and are essential tools in helping us to arrange financing for the construction of our windparks. For further discussion of our hedging strategy, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Revenues."

    Project Financing

        The project finance team structures and negotiates debt and tax equity financings for the construction and operation of our projects, with the goal of minimizing recourse and maximizing our after-tax financial returns, while also preserving our managerial control over the project companies. In support of these activities, the project finance team maintains close relationships with active renewable energy lenders and potential tax equity investors.

        Debt Financing.    Debt for windparks is typically provided by commercial banks and institutional lenders that have the expertise to evaluate the risks associated with the technology, construction, operations and wind resources necessary for windparks. These lenders provide construction financing for most sizable industrial and infrastructure projects. After construction of a windpark has been completed, these banks often remain as lenders at the project level.

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        Project financing options have improved substantially as the market has matured over recent years. Wind technology and project fundamentals are now widely understood by project finance lenders and U.S. institutional investors. According to Project Finance International, the wind sector received 56% of the $35.0 billion of renewable technology project financing issued from 2000 to 2006. For further discussion of our project debt financing arrangements, see "Description of Certain Financing Arrangements—Initial New York Project Financing."

        Tax Equity Financing.    U.S. windparks are currently supported by the ten-year PTC and five-year accelerated tax depreciation. While the PTC can be applied to reduce federal income tax liabilities on a dollar-for-dollar basis and accelerated depreciation can reduce taxable income or generate tax losses, we, like many wind energy companies, do not currently have the taxable income necessary to use these tax benefits. Accordingly, as part of the financing strategy for our windparks, we seek to monetize the value of these tax benefits by entering into investment structures with tax equity investors, who can utilize the benefits. Typically, we will form a limited liability company with the tax investors, who will be allocated most of the tax benefits and will receive significant cash distributions during the ten-year PTC period.

        Typical tax equity investors include large financial institutions, such as banks or insurance companies, utilities or other institutional investors with relatively low funding costs and significant income against which they could apply the tax benefits generated by our windparks. We expect that increasing numbers of participants will be willing to provide tax equity financing in the future, so long as the tax incentives remain available. For example, according to JP Morgan Capital Corporation, in 2006, $3.1 billion in tax equity was raised.

        For a further discussion of our tax equity financing structures, and the tax equity financing related to our Initial New York Windparks, see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Refinancing Upon Commencement of Operations and Tax Equity Financing" and "Risk Factors—The federal government may not extend or may decrease tax incentives for renewable energy, including wind energy, which would have an adverse impact on our development strategy."

Engineering and Construction (E&C)

        As part of our strategy to fully integrate our capabilities across all aspects of windpark development, financing, construction and operations, we have an in-house team of 43 E&C professionals who perform engineering and construction services for many of our projects. Our engineering and construction team has the ability to either act as general contractor on a project, coordinating with third-party construction contractors, or to engage a third-party in the general contractor or construction management role. We make these decisions based on economic benefit to us. We believe that this two-fold construction strategy differentiates us from other independent U.S. wind energy companies, which typically rely only upon third-party general contractors. Our E&C team is comprised of highly experienced project and construction managers, superintendents, field engineers, safety technicians, quality specialists and project control engineers and includes personnel who have supervised the design and construction of power facilities in excess of 5,400 MW over the last ten years. Where we act as general contractor, each project site has a dedicated resident construction manager and team of construction professionals and engineers. Other E&C functions are centralized, which allows the group to efficiently scale its resources to support our developing national platform and growth capabilities. In general, we provide E&C services pursuant to contracts between our E&C subsidiary and each project subsidiary.

        Our E&C team also works closely with our development teams to provide input throughout the development cycle from land acquisition through permitting and financing of our windparks. We provide a highly responsive and flexible approach to resolving any issues that arise during the

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development of a project. Immediate access to engineering and construction expertise enhances our ability to make practical, cost effective decisions during the development cycle. Additionally, the close co-ordination of our development and E&C teams ensures that our construction designs are compatible with permits and landowner agreements to minimize any problems during the construction phase and ensure a timely start of construction.

Operations and Maintenance (O&M)

        We perform O&M services in-house through our experienced and well-trained team of 25 professionals, who have been responsible for the operation of windparks in excess of 2,100 MW over the last ten years. Our O&M department closely monitors the performance of the equipment at our windparks to prevent and minimize downtime. This constant feedback offers managers an effective and timely method to measure their performance and identify areas for improvement and allows us to take preventative action rather than simply reacting to problems. We also use problem-solving tools designed to determine the root cause of problems and to continuously improve quality and maximize run time.

        We have also established a National Operations Center, which allows us to remotely monitor and control, if necessary, each of our turbines from a central location. We have installed equipment that allows us to combine historical trend analysis with real-time operational data to predict possible turbine performance issues. We also employ predictive maintenance techniques, including borescopic visual analysis that tracks the performances of gear boxes, main bearings and generators, as well as infrared camera analysis, which monitors the effectiveness of transformers, collection system connections and control panels. In addition, our meteorology group works closely with our National Operations Center to provide forecast information in support of power scheduling and for windpark performance assessment, which will aid in the scheduling of preventative maintenance services. These predictive tools allow us to perform scheduled repairs instead of reacting to expensive unexpected problems, which we believe helps us reduce the more than 70% of our O&M expenses related to labor and component usage. Through our equipment subsidiary, we also intend to carry key spare wind turbine parts at our National Operations Center, which we believe will result in significant reductions in costs and turbine downtime by enabling us to procure long lead-time components before engaging sub-contractors.

        Our O&M team is easily scalable to meet our growth needs. It works closely with GE, our current turbine supplier, to identify and remedy any turbine component failures as our turbine supply agreements with GE provide us with a two-year warranty on all wind turbine components. We currently have 13 technicians, each of whom has or will undergo an intense training program at the GE Wind Training Center to learn standardized maintenance practices and optimal turbine operation procedures, which minimizes the variability of our maintenance procedures and troubleshooting techniques among our windparks. As we continue to grow our operating portfolio, we plan to expand our O&M team, placing an emphasis on hiring personnel from the local communities in which we operate. As with E&C services, we generally provide O&M services pursuant to contracts between our O&M subsidiary and each project subsidiary. Similarly, while we generally intend to operate and maintain our windparks ourselves, we retain the flexibility to use third-party service providers. This also differentiates us from other independent U.S. wind energy companies.

Asset Management

        We have adopted a commercial strategy of managing our projects and other assets with an in-house asset management team of 11 professionals acting as "owner's representatives." The role of the asset management group is to manage each individual windpark by overseeing the E&C, O&M and parts supply contracts and to closely monitor the performance of each windpark from an owner's point of view in order to maximize financial performance and minimize risk. With a group of seasoned managers from the wind and independent power sectors, our asset management team optimizes the commercial performance of our assets, services the project debt, manages project agreements and

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compliance and has ultimate responsibility for the financial performance of each project. The team also manages our extensive real estate obligations, which currently include approximately 700 individual easements for 26 projects, as well as our corporate insurance program, municipal obligations, home office, remote facilities and mobile assets. Our asset management team is scalable and organized regionally in order to facilitate a seamless transfer of responsibilities from the development team through construction to commercial operations.

Accounting, Legal and Human Resources

        We have developed sophisticated support capabilities in these critical areas through our team of 19 professionals. Our accounting group is responsible for the preparation of our financial statements and related financial reports. The legal group provides direct support to our project development team at all phases of siting and construction and counsels the company and its board of directors on compliance matters. The human resources function oversees all employment policies and procedures, implements recruiting and training and supports our growth.

Our Projects

        We currently have three windparks in operation in New York with a capacity of 282 MW.

    The Noble Bliss Windpark is located in the rolling hills of western New York, within Wyoming County. This 100.5 MW project consists of 67 GE 1.5 MW sle turbines.

    The Noble Clinton Windpark is located in the level highland farmland of northern New York, within Clinton County. This 100.5 MW project consists of 67 GE 1.5 MW sle turbines.

    The Noble Ellenburg Windpark is located in the level highland farmland of northern New York, within Clinton County. This 81 MW project consists of 54 GE 1.5 MW sle turbines.

        We have begun construction of three additional windparks in New York and one windpark in Texas and will soon begin construction of a fourth new windpark in New York, adding a total of 465 MW of capacity to our operating portfolio.

    The Noble Altona Windpark is located in the level highland farmland of northern New York. This 97.5 MW project is expected to consist of 65 GE 1.5 MW sle turbines.

    The Noble Chateaugay Windpark is located adjacent to the Noble Clinton Windpark. This 106.5 MW project is expected to consist of 71 GE 1.5 MW sle turbines.

    The Noble Wethersfield Windpark is located adjacent to the Noble Bliss Windpark. This 126 MW project is expected to consist of 84 GE 1.5 MW sle turbines.

    The Noble Great Plains Windpark is located in the open ranch land of northwestern Texas, within Hansford County on the Oklahoma border. This 240 MW project, 114 MW (Phase I) of which is currently in construction and 126 MW (Phase II) of which will be constructed in 2009, is expected to consist of 160 GE 1.5 MW sle turbines.

    The Noble Bellmont Windpark will be located adjacent to the Noble Chateaugay windpark. This 21.0 MW project is expected to consist of 14 GE 1.5 MW sle turbines.

        In 2009, we plan to construct three additional windparks in New York, the remaining MW at the Great Plains project and one additional windpark in Texas, adding 499.5 MW of capacity to our operating portfolio.

    The Noble Ball Hill/Villenova Windpark will be located in the hills of western New York, within Chautauqua County. This 100.5 MW project is expected to consist of 67 GE 1.5 MW sle turbines.

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    The Noble Centerville/Rushford Windpark will be located in the hills of western New York, within Allegany County. This 100.5 MW project is expected to consist of 67 GE 1.5 MW sle turbines.

    The Noble Chateaugay II Windpark will be located contiguous to the Noble Chateaugay Windpark. This 19.5 MW project is expected to consist of 13 GE 1.5 MW sle turbines.

    The Noble Mitchell County I Windpark will be located in the open ranch land of western Texas, within Mitchell County. This 300 MW project, 153 MW (Phase I) of which will be constructed in 2009 and 147 MW (Phase II) of which will be constructed in 2010, is expected to consist of 200 GE 1.5 MW sle turbines.

        In 2010, we plan to construct two additional windparks in New York, the remaining MW at the Mitchell County I project and one additional windpark in Texas, two new windparks in New England and one new windpark in Minnesota, adding 705 MW of capacity to our operating portfolio.

    The Noble Burke Windpark will be located adjacent to the Noble Chateaugay and Bellmont Windparks. This 60 MW project is expected to consist of 40 GE 1.5 MW sle turbines.

    The Noble Farmersville Windpark will be located in the rolling hills of western New York, within Cattaraugus County. This 100.5 MW project is expected to consist of 67 GE 1.5 MW sle turbines.

    The Noble Mitchell County II Windpark will be located in the open ranch land of western Texas, within Mitchell County. This 351 MW project, 150 MW of which will be constructed in 2010, is expected to consist of 234 GE 1.5 MW sle turbines.

    The Noble Grandpa's Knob Windpark will be located in the high ridgeline of central Vermont, within Rutland County. This 72 MW project is expected to consist of 24 Vestas 3.0 MW V-90 turbines.

    The Noble Granite Reliable Windpark will be located in the high ridgeline of northern New Hampshire, within Coos County. This 75 MW project is expected to consist of 25 Vestas 3.0 MW V-90 turbines.

    The Noble Flat Hill I Windpark will be located in the open farmland of north western Minnesota, within Clay County. This 100.5 MW project is expected to consist of 67 GE 1.5 MW sle turbines.

        We have identified an estimated 1,900 MW of additional windparks that we expect to commence operations in 2011 and 2012. Of this amount, we expect that approximately 50 MW will be located in Maine, 400 MW will be located in Michigan, 200 MW will be located in Minnesota, 175 MW will be located in New York, 800 MW will be located in Texas, 175 MW will be located in Vermont and 100 MW will be located in Wyoming. The windparks in Minnesota, New York, Texas and Vermont will represent additional operations or expansions of our windparks that we expect to be in operation in those states by 2010. The windparks in Maine, Michigan and Wyoming represent new states in our project portfolio. For the majority of these windparks, we have secured a portion of the land necessary to place our turbines and have analyzed the characteristics of the applicable energy, capacity and REC markets. We have also performed preliminary wind analysis, started discussions related to the interconnection process and initiated a dialogue with the local communities.

Competition

        We compete with other renewable energy companies, but principally with those companies in the wind energy industry, including public utilities that are much larger than we are with substantially greater financial resources. In the wind energy sector, competition occurs primarily during the

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development phase, principally in the identification and procurement of suitable sites with high wind resources availability, grid connection capacity and the availability of land, wind turbines, spare parts and the other key equipment we depend on to construct and operate our windparks. Depending on the regulatory framework and our approach in certain regions, we may also face competition for long-term power purchase agreements. Additionally, we face competition for the sale of RECs generated by our windparks and for personnel experienced in the wind power industry.

Customers

        We sell the energy generated by, and we expect to sell the capacity of, our windparks into the market operated by NYISO. We have also agreed to sell the majority of the RECs generated through the operation of these windparks to NYSERDA. For more information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Revenues." We expect that the sale of energy into the market operated by NYISO (net of any gain or loss associated in our energy hedging transactions) and the sale of RECs to NYSERDA will account for approximately 78% and 19%, respectively, of our revenues during 2008. We expect to use similar arrangements with respect to energy, capacity and REC sales with NYISO, NYSERDA and other parties in our future windparks.

        Each regional wholesale electricity market in which we intend to operate is administered by an Independent System Operator, or ISO, or a Regional Transmission Operator, or RTO, which also operate the electric transmission facilities within a specific state or region. Below is a description of the NYISO, where we currently sell our electricity and capacity, and of the other regional markets in which we intend to sell our electricity and capacity.

    The NYISO has been the independent system operator for the New York state transmission system and wholesale electricity markets since 1999. The NYISO consists of 11 different zones or sub-regions which are separated by transmission constraints. The NYISO manages approximately 11,000 miles of transmission lines and more than 300 generation units totaling almost 40,000 MW of capacity. The products that are traded in the NYISO include energy, capacity, and financial transmission rights. Energy markets are comprised of a day-ahead market and a real-time market with pricing based on least-cost bids submitted by electricity generators within each zone. Capacity is sold through a series of auctions for various time periods of the year. Natural gas-fired electric generation sets the market clearing price for electricity for most hours, and summer reserve margins in each of 2005 and 2006 were 17%.

    The Southwest Power Pool, or SPP, is an RTO whose territory covers Kansas, Oklahoma and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas. SPP has 11 load zones and does not currently have a separate capacity market. Market participants trade physical electricity bilaterally, either directly or through brokers, and through the real-time energy imbalance service market. The region is characterized by coal and natural gas on the margin for most hours and had a summer reserve margin of approximately 13-14% during the years 2004 through 2006. Noble expects to build windparks in the parts of Texas located in SPP.

    The ISO New England, or ISO-NE, covers several states in the northeastern United States, including Connecticut, Massachusetts, New Hampshire, Rhode Island, Vermont and parts of Maine. Load zones and locational pricing are differentiated by state, except for Massachusetts, which is divided into three areas: Northeastern Massachusetts, Southeastern Massachusetts and Western/Central Massachusetts. Similar to NYISO, ISO-NE has separate energy and capacity markets with natural gas-fired electric generation also setting the price of electricity for most hours. These markets include day ahead and real-time spot market with locational marginal pricing. Further, summer reserve margins have declined significantly from 29% in 2004 to 10% in 2006.

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    The Electric Reliability Council of Texas, or ERCOT, covers most of Texas and is divided into four zones: Houston, North, South and West. Like SPP, ERCOT is an energy-only market, with no separate transactions for capacity. Market participants trade physical electricity bilaterally, either directly or through brokers, and through the energy imbalance service market. The region currently has excess capacity with some generation recently "moth-balled" or decommissioned. However, according to the FERC, reserve margins are nevertheless expected to decline to levels consistent with the target set by ERCOT of 12.5% target in the next two years. Additionally, summer reserve margins have declined from 26% in 2004 to 14% in 2007. Within ERCOT, natural gas-fired electric generation sets the price of electricity for the majority of hours.

    The Midwest ISO, or MISO, covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, Illinois, Indiana, Michigan and parts of Montana, Missouri, Kentucky and Ohio. MISO is divided into several markets, including Cinergy, First Energy, Illinois, Michigan and Minnesota. Additionally, MISO is an energy-only market with coal-fired electric generation setting the market clearing price for electricity for most hours. The Midwest ISO administers a two-settlement (day ahead and real-time) energy market known as the Day-2 market that produces hourly locational marginal prices. Summer reserve margins have declined from 22% in 2005 to 18% in 2006.

Suppliers

        The key component for our windparks is wind turbines. Turbine costs generally represent between 55% and 65% of our total windpark capital costs. There are a limited number of turbine suppliers and current demand worldwide for turbines exceeds production capacity. See "Risk Factors—We currently rely extensively on one of a small number of wind turbine manufacturers." Our turbine supply strategy is largely based on establishing master supply agreements and developing strong relationships with leading turbine suppliers to secure our turbine needs. GE has supplied us with turbines for our Initial New York Windparks totaling 282 MW, and we have contracted with GE for turbines through 2009 totaling an additional 965 MW. Our contract with GE generally covers the production, erection and commissioning phases and includes a warranty period typically of two years, unless otherwise negotiated. In addition to GE, we maintain an active dialogue with another major turbine supplier, as well as with the suppliers of spare parts for our turbines. The suppliers for two of our key spare parts, namely gear boxes and blades, are located outside of North America. See "Risk Factors—Spare parts for wind turbines and key pieces of electrical equipment may be unavailable to us."

        Our other important suppliers are engineering and construction companies, including suppliers of crane equipment and operators, that are contracted during the development and construction stages to perform certain work for our windparks, including the construction of portions of the required infrastructure.

Employees

        As of May 5, 2008, we had 152 employees, of which 64 are based in our corporate headquarters, 82 are based in our various project offices and 6 are based in our National Operations Center. None of our employees are represented by a labor union. We believe that we have a good relationship with our employees, and we have never experienced any labor dispute, strike or work stoppage.

Insurance

        We maintain business interruption insurance, casualty insurance, including flood and earthquake coverage, primary and excess liability insurance, customary workers' compensation, automobile insurance and such other insurance as is generally carried by companies engaged in a similar business in the same general areas. In addition, at the individual project companies, we maintain builder's "all risk" insurance coverage for each windpark under construction as well as business interruption and operational risk coverage for each windpark in operation. These project company policies are sized on a project-by-project basis.

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Regulation

        The following is a summary overview of certain applicable regulations in the United States and should not be considered a full statement of the law or all related issues.

Energy Regulation

    FPA

        Under the Federal Power Act, or FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. The FPA subjects "public utilities" within the meaning of the FPA, among other things, to rate and corporate regulation by FERC. In particular, sellers of electricity at wholesale in interstate commerce and transmitters of electricity in interstate commerce are regulated by FERC with respect to: the review of the terms and conditions of wholesale electricity sales and transmission of electricity; the need to obtain advance approval of certain dispositions of public utility facilities, mergers, purchases of securities of other public utilities, acquisitions of existing generation facilities and changes in upstream ownership interests; the regulation of their borrowing and securities issuances and assumption of liabilities; and the review of interlocking directorates. Future issuances of our equity securities may also be subject to FERC approval under Section 203 of the FPA. FERC has authority under Section 206 of the FPA in certain circumstances to order refunds and, under FPA amendments pursuant to the Energy Policy Act of 2005, FERC has expanded authority to assess civil penalties of up to $1 million per day for violations of the FPA. We can offer no assurance that, at some future time, Congress will not change the relevant provisions of the FPA, or that FERC will not change its regulations implementing the requirements of the FPA.

        Wholesale electricity sellers authorized by FERC to sell at market-based rates may obtain waivers or blanket pre-approvals as to certain of the regulatory requirements of the FPA, including waiver of FERC's accounting regulations and blanket pre-authorization with respect to its regulation of issuances of securities and assumption of liabilities. We can offer no assurance that FERC will not revisit its policies at some future time with the effect of limiting market-based rate authority, regulatory waivers and blanket authorizations. Each of our Initial New York Windparks and certain of our other windparks have been granted market-based rate authority, and as a result, may sell electric energy and capacity at market or otherwise negotiated rates. While our Texas windpark has obtained QF status pursuant to PURPA and FERC's implementing regulations, we anticipate that our Texas windpark will sell electricity at wholesale pursuant to market-based rate tariff on file with FERC, rather than pursuant to a PURPA contract. As a result of the grant of market-based rate authorization by FERC, each of our Initial New York Windparks and our other windparks with market-based rate authorization is subject to regulation by FERC as a "public utility" pursuant to the FPA. FERC's orders that grant market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that the market-based rate seller can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where it determines market power may exist and that the public interest requires such potential market power to be mitigated. We are also required to report to FERC any material changes in status that would reflect a departure from the characteristics that FERC relied upon when granting market-based rate authority, make quarterly electronic filings with FERC providing information on sales of electricity and comply with market behavior and manipulation rules. If any of our windparks were to lose its market-based rate authority, it would be required to obtain FERC's acceptance of cost-of-service rate schedules and would become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

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        In addition to direct regulation by FERC, our windparks are subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by FERC, they can impose rules, restrictions and terms of service on market participants, like our windparks, that can have a material impact on our business. For example, ISOs and RTOs may impose bidding and scheduling rules, both to curb market power and to ensure functioning markets.

        FERC rules for the establishment, approval and enforcement of Electric Reliability Standards require each of our windparks to register with the North American Electric Reliability Council and the regional Electric Reliability Organization. We are also required to comply with applicable Reliability Standards approved by FERC.

    PUHCA and PURPA

        The Public Utility Holding Company Act of 2005, or PUHCA, in relevant part, provides that any entity that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a "public utility company" (which is defined to include an "electric utility company") or a company that is a "holding company" of a public utility company or public utility holding company, is subject to certain regulations granting FERC, access to books and records and oversight over certain affiliate transactions. State regulatory commissions may in some instances also have access to books and records of holding companies. Entities that are holding companies solely by virtue of their ownership of qualifying facilities, or QFs, and exempt wholesale generators, or EWGs, are exempt from FERC access to books and records under PUHCA. In order to obtain EWG status pursuant to PUHCA, the owner of a generating facility must demonstrate that it is engaged directly, or indirectly through one or more affiliates, and exclusively in the business of owning and/or operating facilities used exclusively for the generation of electricity for sale at wholesale. In order to obtain QF status pursuant to PURPA, a generating facility must qualify as a small power production facility or cogeneration facility that has either filed a self-certification of QF status with, or has received a QF certification order from, FERC. A wind generation facility may qualify as small power production facility QF if it is less than 80 MW. We have received QF status designation from FERC for our Texas windparks.

        Each of our Initial New York Windparks has filed a self-certification with the FERC that it is an EWG. As a result, under current federal law, we are not subject to regulation as a holding company under PUHCA and will not be subject to this regulation as long as each "public utility company" in which we have an interest is (i) a QF, (ii) an EWG or (iii) subject to another exemption or waiver.

    State Regulation

        Some of our windparks are or will be subject to varying degrees of regulation by state public utility commissions, or PUCs. PUCs have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities that sell electricity at retail, and a number of other matters relating to electric utilities, as described below. State laws may also impose certain regulatory and reporting requirements on other owners and operators of generation facilities. Independent power producers are considered to be public utilities in some states and are subject to varying degrees of regulation by PUCs, ranging from a requirement to obtain a "certificate of public convenience and necessity" in order to construct and operate a generating facility, to regulation of organizational, accounting, financial and other corporate matters. While FERC has exclusive jurisdiction over the rates for wholesale sales of electric energy, states may assert jurisdiction over the location and construction of electric generating facilities, and in certain situations, over the issuance of securities and the sale or other transfer of assets by these facilities.

        In New York, the New York Public Service Commission, or PSC, has asserted only limited authority over generation facilities selling exclusively into the wholesale market. The PSC's regulation

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of electricity suppliers does not include regulation of the rates that New York generators may charge. However, the PSC requires new generators to obtain operating licenses pursuant to the state Public Service Law, or PSL, and may condition those licenses on the generator's compliance with siting and operating restrictions. Our Initial New York Windparks have received such licenses from the PSC, as have the projects we expect to build in Altona, Bellmont, Chateaugay and Wethersfield, New York.

        Section 70 of the PSL requires electric corporations, such as our Initial New York Windparks, to obtain approval of the PSC in advance for certain dispositions of their facilities, mergers, purchases of securities of other public utilities and changes in upstream ownership interests. Each of our Initial New York Windparks has obtained a determination from the PSC that it will be subject to "lightened regulation" by the PSC. For lightly regulated electric corporations like the Initial New York Windparks, there is a presumption that no PSC approval will be required under Section 70 of the PSL for the transfer of ownership interests (including transfers of stock) in entities upstream from the Initial New York Windparks, unless there is a potential for harm to the interests of captive utility ratepayers, which is sufficient to override the presumption. For electric corporations owning generators that make wholesale sales of electricity (such as our Initial New York Windparks), the potential for the exercise of market power arising from an upstream transfer would be sufficient to defeat the presumption and trigger Section 70 review.

        The PSC also regulates borrowing and securities issuances by electric corporations under Section 69 of the PSL. However, Section 69 does not apply to issuances of stock by an upstream owner of an electric corporation, such as the issuer.

        As in New York, the Public Utility Commission of Texas, or PUCT, has limited jurisdiction over power generation companies selling exclusively into the wholesale market. The PUCT requires power generators and sellers of RECs to register, and enforces various rules addressing market power, market manipulation, and reliability. The state also has authority to approve certain mergers, consolidations and affiliations involving power generation companies.

        The power generation company, or PGC, is also required to register with the applicable Electric Reliability Organization for the region. Our planned Noble Great Plains Windpark is located in SPP and the planned Noble Mitchell County Windpark is located in ERCOT. In addition to registering the facility as a resource with SPP and ERCOT, and after the PUCT has certified the PGC facility as a REC generator, the PGC will also need to enter into a REC account agreement and establish a REC account with ERCOT, as the statewide administrator of the REC program.

Environmental Regulation

        Our windpark development activities are subject to various federal, state and local environmental laws and regulations, primarily including environmental impact review requirements and regulations governing the discharge of fill materials into protected wetlands. The impact of these laws and regulations on the development, construction and operation of our windparks is site specific and varies depending upon the location and design of the windpark and the relevant state and local laws and regulations. In New York, for example, the State Environmental Quality Review Act requires us to evaluate the potential environmental impacts caused by our windparks, including assessments of visual and noise impacts, effects on wildlife (primarily birds and bats) and impacts to historical and cultural resources, and to implement measures to mitigate those impacts to the extent practicable. Local laws may also regulate other aspects of our windpark development and operation, by setting limits on the use of local roads, setback requirements and noise standards. If we fail to comply with these requirements, or with other regulatory standards, we may be denied permits that are required for construction or operation or become subject to regulatory enforcement actions. Project opponents frequently use environmental impact review statutes as a basis for mounting legal challenges to the issuance of permits and approvals. Legal challenges or enforcement actions, even if ultimately defeated,

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can result in substantial delays in the completion of a windpark and may have a material adverse effect on our business, results of operations and financial condition.

        Our windparks are designed to have minimal operational impact on the environment. Operation of a windpark does not produce significant wastes, generate air emissions or result in wastewater discharges. While most of our environmental regulatory obligations arise during or prior to the construction stage for some windparks, significant environmental obligations may still exist even after construction is complete. For example, the Initial New York Windparks are obligated to monitor impacts on avian species and to adopt mitigating measures if we detect substantial impacts. In most cases, the precise nature of this potential mitigation is not specified in the windparks' permits. While we do not currently anticipate that any material mitigation efforts will be required, we cannot offer any assurance that the mitigation will not have an adverse effect on our business, results of operations or financial condition. We may also be required to mitigate for damage to or loss of wetland areas which, in some instances, may not be completed for several years after the windpark is constructed. We do not anticipate that such mitigation efforts will require material expenditures, but any failure to complete such mitigation could result in fines or penalties and make it more difficult for us to procure similar permits for future windparks.

Legal Proceedings

        We do not have any material legal proceedings which are currently pending. From time to time, we and our subsidiaries may be party to various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our business. These actions may seek, among other things, compensation, civil penalties or other losses, or injunctive or declaratory relief. Additionally, although no such claims are currently pending, we or our individual project subsidiaries may be subject to legal proceedings contesting the validity of one or more permits or otherwise challenging our authorization to construct and operate windparks.

Properties

        We lease our corporate offices (approximately 16,000 square feet) at 8 Railroad Avenue, Essex, Connecticut 06426. We also occupy an aggregate of approximately 18,000 square feet of project office space in Altona, Arcade, Bliss, Churubusco and Fredonia, New York; Austin and Hitchland, Texas; Lancaster, New Hampshire and Rutland, Vermont, which we lease in the form of office trailers or existing built out space. Additionally, our National Operations Center is located in a 9,750 square foot leased facility in Plattsburg, New York. We believe that our current facilities are adequate for our operations as currently conducted and if additional facilities are required, that we could obtain them at commercially reasonable prices.

        We generally do not own the property underlying our windparks. Instead, we usually obtain easements from the landowners that give us the right to install our meteorological equipment, turbines, transmission lines and related equipment and prohibit the landowners from building other structures that would interfere with the operation or maintenance of the windpark. The terms of the easement agreements vary, but usually cover a development period, a construction period, and a 20-year operational period, with our option to extend the operational period for an additional 30 years. Our easement agreements generally obligate us to make payments to the landowner based on revenues to be generated from assets located on the landowner's property. During the construction phase of a particular windpark, we may acquire land for the siting of facilities needed by the transmission system operator to accommodate the windpark; we typically transfer these real estate interests to the transmission system operator once construction of the windpark is complete. See "—Organization of Our Business—Development—Site Selection, Land Control and Permitting."

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MANAGEMENT

Directors and Executive Officers

        The following table sets forth information concerning our directors and executive officers as of the completion of this offering.

Name

  Age
  Position
Walter Howard   56   President, Chief Executive Officer and Director

Charles Hinckley

 

45

 

Executive Chairman and Director

John Quirke

 

56

 

Executive Vice President, Development

Christopher Lowe

 

40

 

Executive Vice President and Chief Financial Officer

C. Kay Mann

 

50

 

Senior Vice President, General Counsel and Secretary

Thomas Swank

 

40

 

Senior Vice President, Commodities and Risk Management

Daniel Mandli

 

50

 

Senior Vice President, Operations

Stephen Murray

 

45

 

Director

Christopher Behrens

 

47

 

Director

Nancy-Ann DeParle

 

51

 

Director

John Warner

 

39

 

Director

Barry Goldstein

 

65

 

Director

        All our current executive officers hold their offices at the pleasure of our board of directors, subject to rights under their respective employment agreements. There are no family relationships between or among any directors and executive officers.

        Walter Howard.    Walter Howard, our President and Chief Executive Officer, joined us in April 2008. From 2005 to April 2008 Mr. Howard served as the Senior Vice President—Sales and Business Development of American Water Works Company, Inc., a non-governmental water supplier and water utility. From 2004 to 2005, he served as a consultant at General Electric, where he initiated a large scale desalination and municipal drinking water business. From 2002 to 2004, he served as Chief Executive Officer of Noble Power Assets, LLC, a company founded by certain members of our senior management team to acquire assets in the unregulated electric power generation industry. From 1995 to 2002, he founded and served as CEO of Poseidon Resources, a company which applied project financing and development techniques developed in the cogeneration and IPP markets to water projects. Prior to that, he was Executive Vice President of US Generating Company, and CFO of the J. Makowski Company, early innovators in the cogeneration and IPP marketplace. Mr. Howard earned a BS in engineering and a Masters in civil and environmental engineering from Cornell University and an MBA from Harvard Business School, and is a licensed engineer.

        Charles Hinckley.    Charles Hinckley, our Executive Chairman, co-founded us in 2004 and was our President and Chief Executive Officer until April 2008. From 2002 to April 2004, Mr. Hinckley served as Senior Vice President of Noble Power Assets. From 1998 to 2002, Mr. Hinckley was the Manager of CC Hinckley Co., LLC, working for clients such as United Technologies Corporation and GE Capital, where he developed the five CalPeak power plants in California in 2001 and 2002, and the GTi Dakar power plant in Senegal from 1998 to 2000. From 1997 to 1998, he was a manager at GE Capital where he worked in international power plant development. From 1991 to 1996, he was an operations and business development executive for Kenetech Corporation, an early pioneer in the wind power industry.

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From 1989 to 1991, he worked at what is now GE Power Systems where he was a manager in their power plant operations and maintenance business. Mr. Hinckley earned a BS in physics from Miami University.

        John Quirke.    John Quirke, our Executive Vice President, Development, co-founded us in 2004. In 2003 he worked at Noble Power Assets. While at Noble Power Assets he advised and performed due diligence on power asset acquisitions on behalf of two private equity funds. From 2000 to 2002, Mr. Quirke served as Chief Executive Officer of United Technology Energy Holdings where he led a power project development joint venture with United Technologies Corporation. Mr. Quirke earned a BE in civil engineering from the National University of Ireland and did his post graduate work in operations research at Trinity College in Dublin.

        Christopher Lowe.    Christopher Lowe, our Executive Vice President and Chief Financial Officer, joined us in June 2007. From March 2005 to June 2007, he served as Managing Director at HSBC Securities where he ran the Americas Resources & Energy Group in the Global Banking division. From February 2003 to February 2005, he was a Managing Director at J.P. Morgan Securities Inc., within the Natural Resources Group in the Investment Banking Division where he focused on the power and utilities sector. From April 1990 to February 2003, Mr. Lowe held a number of positions at J.P. Morgan Securities, Inc., and its predecessor, Chase Securities, Inc., in the project finance, private placements, capital markets, and investment banking coverage groups. Mr. Lowe earned an MA in mathematics from the University of Cambridge in the United Kingdom and is also a CFA Charterholder.

        C. Kay Mann.    C. Kay Mann, our Senior Vice President, General Counsel and Secretary, joined us in April 2008. From June 2002 to April 2008, Ms. Mann worked as Senior In-House Counsel at General Electric, where she was responsible for providing legal support including compliance, transactions, corporate governance, risk identification and policy development, legal resource evaluation and management, labor and employment, and litigation, to various groups within GE's energy and oil and gas divisions. From May 1999 to June 2002, Ms. Mann served as Senior In-house Counsel at Enron Corporation, where she served as Assistant General Counsel, Wholesale Services and Senior Counsel, Engineering and Construction. From February 1992 to May 1999, Ms. Mann served as Vice President and General Counsel at Technip USA, where she advised on all legal matters in connection with the engineering, procurement and construction business. Ms. Mann earned a BA in political science and a JD from the University of Houston.

        Thomas Swank.    Thomas Swank, our Senior Vice President, Commodities and Risk Management, joined us in 2005. From 2004 to 2005 Mr. Swank served as Vice President of Power Origination for Sempra Energy Trading Corp. where he was responsible for structuring power transactions in the eastern U.S. From 2003 through 2004, he was a principal in Colonnade Energy, LLC, a consulting firm focused on providing services to clients in support of merchant energy space. From 2000 to 2002, Mr. Swank held senior executive positions at El Paso Merchant Energy and served as Senior Vice President, Structured Transactions with responsibility for the firm's power and cross-commodity origination efforts for North America and as Senior Vice President of Mergers and Acquisition. From 1999 to 2000, he was Director of Origination for Enron North America, responsible for originating gas and power transactions in the eastern U.S. From 1994 to 1999, he was employed by Dynegy Corp. in various positions, including Senior Director of Power Assets, where he was responsible for the acquisition and commercial management of several power generation asset portfolios, including West Coast Power, a 3,000 MW joint venture with NRG Energy. From 1999 to 2005 Mr. Swank was a member of the Board of Directors of Rocky Mountain Gas, Inc., a start-up E&P company in Riverton, Wyoming that was a majority owned subsidiary of US Energy Corporation. Mr. Swank earned a BS in commerce from the University of Virginia.

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        Daniel Mandli.    Daniel Mandli, our Senior Vice President, Operations, joined us in 2006. From 2004 to 2006, Mr. Mandli served as General Manager of Wind Operations for FPL Energy, where he managed the operations of FPL's windparks in eight states and oversaw the implementation of the company's diagnostic center. From 1998 to 2004, he was the Director of Service, Installation and Engineering for NEG Micon USA, where he directed the North American Customer Service Organization for NEG wind turbine projects with operations in the United States and Canada. Mr. Mandli earned a BS in chemical engineering from the University of Wisconsin and an MBA from the University of Illinois, Champaign Urbana.

        Stephen Murray.    Stephen Murray has served as a director since August 2007. Mr. Murray is President and Chief Executive Officer of CCMP Capital Advisors, LLC, a private equity firm formed in August 2006 by the former buyout/growth equity investment team of J.P. Morgan Partners, LLC, a private equity division of JPMorgan Chase & Co., and is a member of CCMP Capital's Investment Committee. Mr. Murray focuses on investments in consumer, retail and services, financial services and healthcare infrastructure. Prior to joining J.P. Morgan Partners in 1989, Mr. Murray was a Vice President with the Middle-Market Lending Division of Manufacturers Hanover. Currently, he serves on the board of directors of Cabela's Incorporated and Warner Chilcott Holdings Company, Ltd. Mr. Murray earned a BA from Boston College and an MBA from Columbia University Business School.

        Christopher Behrens.    Christopher Behrens has served as a director since March 2006. Mr. Behrens is a Managing Director in the New York office of CCMP Capital Advisors, LLC and a member of the firm's Investment Committee. He focuses on making investments in the industrial, distribution and energy sectors. Prior to joining J.P. Morgan Partners in 1994, he was a Vice President in the Merchant Banking Group of The Chase Manhattan Corporation. Mr. Behrens earned a BA from the University of California, Berkeley and an MA from Columbia University.

        Nancy-Ann DeParle.    Nancy-Ann DeParle has served as a director since October 2007. Ms. DeParle is a Managing Director in the New York office of CCMP Capital Advisors, LLC and an Adjunct Professor of Health Care Systems at the Wharton School of the University of Pennsylvania. She is also a member of the Medicare Payment Advisory Commission (MedPAC), which advises Congress on Medicare payment and policy issues. Prior to joining CCMP Capital in August 2006, she was a senior advisor to J.P. Morgan Partners since May 2001 and she served as Administrator of the Health Care Financing Administration (HCFA), now the Centers for Medicare and Medicaid Services (CMS), as Associate Director for Health and Personnel at the White House Office of Management and Budget (OMB) and as the Tennessee Commissioner of Human Services. Currently, she serves on the board of directors of Boston Scientific Corporation, Cemer Corporation and DaVita Inc. Ms. DeParle earned a BA from the University of Tennessee and a JD from Harvard Law School. She also earned a BA and an MA in politics and economics from Balliol College of Oxford University, where she was a Rhodes Scholar.

        John Warner.    John Warner has served as a director since May 2007. Mr. Warner is a Principal in the New York office of CCMP Capital Advisors, LLC. He focuses on making investments in the energy, industrial, automotive and consumer sectors. Prior to joining J.P. Morgan Partners in 2000, Mr. Warner was an investment professional at FS Private Investments and Riverside Partners and a strategy consultant at Monitor Company. Mr. Warner earned a BA from Brigham Young University and an MBA from Harvard Business School.

        Barry Goldstein.    Barry Goldstein has served as a director since January 2008. In October 2000, Mr. Goldstein retired as Executive Vice President and Chief Financial Officer of Office Depot, Inc., which he joined as Chief Financial Officer in May 1987. Mr. Goldstein was with Grant Thornton from 1969 through May 1987, where he was named a Partner in 1976. Mr. Goldstein currently serves on the

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board of directors of Interline Brands, Inc. He earned a BS in economics from the University of Pennsylvania.

        We intend to avail ourselves of the "controlled company" exception under The NASDAQ Stock Market rules which eliminates the requirement that we have a majority of independent directors on our board of directors and that we have compensation and nominating committees composed entirely of independent directors, but retains the requirement that we have an audit committee composed entirely of independent directors. Our board of directors currently consists of 7 directors. Within three months following the closing of this offering, our board of directors will consist of              directors, including two independent directors designated by the sponsors. We expect to add one additional independent director, also designated by the sponsors, to our board of directors within twelve months after the closing of this offering.

        Pursuant to our certificate of incorporation, our board of directors will be divided into three classes. The members of each class will serve for a staggered, three-year term. Upon the expiration of the term of a class of directors, directors in that class will be elected for additional three-year terms, subject to the sponsors' board designation rights, at the annual meeting of stockholders in the year in which their term expires. The classes are composed as follows:

              will be Class I directors, whose terms will expire at the 2009 annual meeting of stockholders;

              will be Class II directors, whose terms will expire at the 2010 annual meeting of stockholders; and

              will be Class III directors, whose terms will expire at the 2011 annual meeting of stockholders.

        Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of our directors. This classification of our board of directors may have the effect of delaying or preventing changes in control of our company.

        If at any time we cease to be a "controlled company" under The NASDAQ Stock Market rules, the board of directors will take all action necessary to comply with the applicable NASDAQ Stock Market rules, including appointing a majority of independent directors to the board and establishing certain committees composed entirely of independent directors within the time required by The NASDAQ Stock Market rules.

Committees of the Board of Directors

Audit Committee

        Upon consummation of this offering, our audit committee will consist of Christopher Behrens, Barry Goldstein and John Warner. The board of directors has determined that Mr. Goldstein is an independent director and qualifies as an audit committee financial expert as defined in the rules and regulations of the SEC and under The NASDAQ Stock Market listing standards. Within three months of the closing of this offering, the sponsors will nominate one additional independent director to the audit committee and remove one interested director. Within one year of the closing of this offering, the sponsors will nominate one additional independent director to the audit committee and remove the interested director so that our audit committee will be comprised of three members, all of whom will be independent and financially literate.

        The principal duties and responsibilities of our audit committee are as follows:

    to monitor our financial reporting process and internal control system;

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    to appoint and replace our independent registered public accounting firm from time to time, determine their compensation and other terms of engagement and oversee their work;

    to oversee the performance of our internal audit function; and

    to oversee our compliance with legal, ethical and regulatory matters.

        The audit committee will have the power to investigate any matter brought to its attention within the scope of its duties. It will also have the authority to retain counsel and advisors to fulfill its responsibilities and duties.

Compensation Committee

        Upon consummation of this offering, our compensation committee will consist of Christopher Behrens, Walter Howard and Stephen Murray.

        The principal duties and responsibilities of our compensation committee are as follows:

    to provide oversight on the development and implementation of the compensation policies, strategies, plans and programs for our key employees and outside directors and disclosure relating to these matters;

    to review and approve the compensation of our chief executive officer and our other executive officers; and

    to provide oversight concerning the compensation of our chief executive officer, succession planning, performance of the chief executive officer and related matters.

Nominating and Governance Committee

        Upon consummation of this offering, our nominating and governance committee will consist of Nancy-Ann DeParle, Charles Hinckley and Stephen Murray.

        The principal duties and responsibilities of the nominating and governance committee will be as follows:

    to establish criteria for board and committee membership and recommend to our board of directors proposed nominees for election to the board of directors and for membership on committees of the board of directors; and

    to make recommendations to our board of directors regarding board governance matters and practices.

Code of Business Conduct and Ethics

        We have a Code of Business Conduct and Ethics that applies to all of our employees, including our principal executive officer, principal financial officer and principal accounting officer, or persons performing similar functions. These standards are designed to deter wrongdoing and to promote honest and ethical conduct. The Code of Business Conduct and Ethics, which addresses the subject areas covered by the SEC's rules, will be posted on our website. Any substantive amendment to, or waiver from, any provision of the Code of Business Conduct and Ethics with respect to any senior executive or financial officer shall be posted on this website. The information contained on our website is not part of this prospectus.

2007 Director Compensation

        During 2007, our non-employee managers received no cash compensation. We currently do not have a standard compensation program for non-employee managers, except as described in "Certain

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Relationships and Related Transactions—Other Transactions." However, we plan to evaluate compensation for non-employee directors and may adopt a compensation program in the future. Such a program may include cash as well as equity components.

Compensation Discussion and Analysis

        This section discusses the material elements of compensation awarded to, earned by or paid to our principal executive officer, our principal financial officers and our three other most highly compensated executive officers in 2007. In 2007, Anne Edgley served as our principal financial officer from January 2007 to June 2007. Mr. Lowe, our current principal financial officer, assumed that role in June 2007. These individuals are referred to as our "named executive officers." This discussion and analysis of compensation arrangements of our named executive officers for 2007 should be read together with the compensation tables and related disclosures set forth below. This discussion and analysis contains certain forward-looking statements that are based on our current plans, considerations, expectations and determinations regarding compensation programs that we may adopt in the future. The actual compensation programs that we adopt in the future may differ materially from our current plans, considerations, expectations and determinations as summarized in this discussion and analysis.

Our Compensation Philosophy

        Our compensation philosophy is to maximize long-term stockholder value by providing compensation with the following two objectives:

    Recruiting and retaining executives, including named executive officers, with the skills necessary to lead us to meet or exceed our annual and long-term projections for corporate performance; and

    Creating incentives for executives, including named executive officers, to meet or exceed our annual and long-term projections for corporate performance.

        We believe that we need to provide competitive compensation to achieve our objective of recruiting and retaining qualified executives. We also believe that we need to reward the unique contributions made by each executive to corporate performance in order to achieve our objective of creating incentives for such executives to meet or exceed our annual and long-term projections for such performance.

Role of the Board of Managers, Executive Officers and Consultants

        As the representative of our members, our Board of Managers determined our compensation philosophy in 2007, each element of compensation that our named executive officers were eligible to receive for 2007 service, and the amount that our named executive officers were eligible to receive, and ultimately did receive, under each element of compensation for 2007 service. The Board of Managers coordinated with certain named executive officers and an independent compensation consultant to generate information material to such determination. The process that our Board of Managers followed in making each compensation determination described in this paragraph, and the rationale of our Board of Managers for each such determination, are described in greater detail below in "—Elements of Our Executive Compensation Program."

        In 2007, the Board of Managers requested that our named executive officers provide information primarily relevant to its determination of annual cash bonuses. The specific items of information requested by the Board of Managers is described in greater detail below in "—Annual Cash Bonus." The Board of Managers also requested that our named executive officers discuss their position and their duties with independent compensation consultants, to assist such consultants in developing the compensation analysis described in greater detail below.

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        During the second half of 2007, the Board of Managers engaged Frederic W. Cook & Co., or Cook, to serve as its independent consultant with respect to executive compensation. Specifically, Cook assisted the Board of Managers in structuring the executive compensation program that would become effective upon completion of this offering, including suggesting terms for (i) new employment and change in control severance agreements for our executives, including our named executive officers, and (ii) new annual incentive and long-term incentive plans applicable to our executives, including our named executive officers.

        In connection with structuring the executive compensation program that would become effective upon completion of this offering, the Board of Managers asked Cook to prepare an analysis of the compensation of senior executive officers at other companies in the energy and utilities sector that the Board of Managers deemed comparable to us, and a comparison of the compensation of our named executive officers against the range of compensation of such senior executive officers serving in similar positions with similar duties. The Board of Managers compared its determination of annual cash bonuses for our named executive officers for 2007 against the analysis to ensure that such bonuses were reasonable, in that they fell within a range of bonuses paid to senior executives serving comparable companies in similar positions with similar duties.

        Cook prepared the analysis described above using two different groups of compensation data. First, Cook used compensation data from 16 companies that the Board of Managers deemed to be our peer group, while recognizing that no companies with publicly available compensation information would fall into the private wind company category. Given the lack of public wind companies and the lack of compensation data regarding private wind companies, such companies were all located in the energy sector, had all completed initial public offerings, and had revenue, EBITDA, net income, market capitalization, total assets, long-term debt, locations and employee populations that the Board of Managers reasonably projected would be comparable to us in some respects after completion of this offering and after we achieve certain operational and growth objectives described in this prospectus. The following companies comprised our peer group: Bill Barrett Corporation; Cheniere Energy, Inc.; Clean Energy Fuels Corp.; Concho Resources Inc.; Energy Conversion Devices, Inc.; Evergreen Solar, Inc.; EXCO Resources, Inc.; ITC Holdings Corp.; Linn Energy, LLC; Ormat Technologies, Inc.; Rosetta Resources Inc.; US BioEnergy Corp.; Venoco, Inc.; VeraSun Energy Corporation; Warren Resources, Inc.; and Whiting Petroleum Corporation. Second, Cook used compensation data from the following survey sources: (i) the IPHRA Power Industry Compensation Survey 2007; (ii) survey data aggregated by Salary.com for companies in the energy and utilities sector with 200 to 500 employees located in Connecticut; and (iii) survey data aggregated by Salary.com for companies in the energy and utilities sector with 200 to 500 employees located in New York. Cook did not disclose the name of each company included in such survey sources and provided to the Board of Managers a summary analysis of the survey sources. The final determination made by the Board of Managers with respect to the annual cash bonuses for our named executive officers for 2007 is described in greater detail below in "—Annual Cash Bonus."

Elements of Our Executive Compensation Program

        The principal element of our 2007 executive compensation program was annual cash compensation (i.e., base salary and annual cash bonus). We also have provided some named executive officers with limited perquisites that are consistent with the objectives of our executive compensation programs, as discussed below.

        Each of these compensation elements satisfies one or more of our compensation objectives regarding recruitment, retention and creating incentives for outstanding corporate performance, as described more fully below. We have not adopted any policies with respect to allocating compensation between annual cash compensation and long-term equity compensation, but feel that both elements are necessary for achieving our compensation objectives. Annual cash compensation provides financial

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stability for each of our named executive officers, and strong incentives to contribute to meeting or exceeding our annual projections of corporate performance. Long-term equity compensation provides strong incentives for our named executive officers to contribute to meeting or exceeding long-term projections of corporate performance.

    Annual Cash Compensation

        Base Salary.    A competitive base salary is important to our compensation philosophy of maximizing long-term stockholder value because (i) it enables us to recruit and retain qualified executives, including named executive officers, and (ii) it provides executives, including named executive officers, with immediate incentives to contribute to corporate performance, by affording them with a measure of financial stability in exchange for such contributions.

        Each of our named executive officers, except Mr. Quirke and Ms. Edgley, entered into an employment agreement with us which was effective in 2007 and which established an initial base salary. The employment agreements were the result of arms-length negotiation, and the Board of Managers made a subjective determination that the initial base salary contained in each agreement was competitive and reasonable given the responsibilities, roles and seniority of the relevant named executive officer.

        The Board of Managers made the following decisions with respect to initial base salaries for the named executive officers in 2007:

    Mr. Hinckley received no base salary prior to November 2007. Instead, C.C. Hinckley Co, LLC received a guaranteed monthly payment of $30,000. The guaranteed monthly payment was put in place in the early stages of our development. The guaranteed monthly payments were paid until Mr. Hinckley began to receive a base salary in November 2007.

    In September 2007, we entered into an employment agreement with Mr. Hinckley, which provided him with an initial base salary of $420,000. He began to receive payments in accordance with the employment agreement in November 2007.

    As mentioned above, Mr. Quirke did not receive a base salary in 2007. Like Mr. Hinckley, he received a guaranteed monthly payment of $30,000. The guaranteed monthly payment was put in place in the early stages of our development.

    Pursuant to an employment offer letter, Ms. Edgley received an initial base salary of $276,000 per year. Her initial base salary was established through arms-length negotiation prior to her beginning employment with us. At the beginning of 2007, we increased her base salary to $281,520 as a cost of living adjustment. As of April 8, 2008, Ms. Edgley is no longer our employee.

    In June 2007, we entered into an employment agreement with Mr. Lowe, which provided him with an initial base salary of $300,000.

    In April 2006, we entered into an employment agreement with Ms. Grisaru, which provided her with an initial base salary of $300,000. At the beginning of 2007, we increased her base salary to $306,000 as a cost of living adjustment.

    In August 2005, we entered into an employment agreement with Mr. Swank, which provided him with an initial base salary of $300,000.

        Annual Cash Bonus.    A competitive annual cash bonus is important to our compensation philosophy of maximizing long-term stockholder value because (i) it enables us to recruit and retain qualified executives, including named executive officers, and (ii) it provides executives, including named executive officers, with incentives to make contributions crucial to our corporate performance, by

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providing them with compensation if we meet or exceed our annual projections for corporate performance. Historically, our annual bonuses have been paid in cash and traditionally have been paid in a single installment in the first quarter following the completion of a given fiscal year.

        In determining the amount of annual cash bonus that each named executive officer received for 2007 service, the Board of Managers considered the following four factors: (i) the established targets for such bonuses in certain employment agreements for named executive officers effective in 2007; (ii) our actual corporate performance in 2007 relative to our projected corporate performance at the beginning of 2007; (iii) the contributions made by each named executive officer to our corporate performance in 2007; and (iv) a market check against the analysis prepared by Cook, as further described above in "—Role of the Board of Managers, Executive Officers and Consultants." Each executive officer, with the exception of Ms. Edgley, received a cash bonus in 2007.

    Established Targets in Employment Agreements

        Pursuant to employment agreements effective in 2007, each named executive officer, except Mr. Quirke, was eligible to receive an annual cash bonus. Each named executive officer, except Mr. Quirke and Ms. Edgley, had an established target in his or her employment agreement for the amount of the annual cash bonus. As mentioned above, the employment agreements were the result of arms-length negotiation, and the Board of Managers made a subjective determination that the established target contained in each agreement was competitive. The following are the established targets for each named executive officer, other than Mr. Quirke and Ms. Edgley: (i) 100% of base salary for Mr. Hinckley; (ii) 66.67% of base salary for Mr. Lowe; (iii) between 25% and 50% of base salary for Ms. Grisaru; and (iv) anticipated to be no less than $250,000 for Mr. Swank. Notwithstanding the established target, the employment agreement for Mr. Hinckley provided him with a guaranteed minimum bonus for 2007 equal to 25% of his base salary. The guaranteed minimum bonus was the result of arms-length negotiations with Mr. Hinckley over his employment agreement. As mentioned above, we did not enter into an employment agreement with Mr. Quirke in 2007. The process for determining the discretionary payment for Mr. Quirke and Ms. Edgley is the same as the process for determining the annual cash bonus for the other named executive officers.

    Corporate Performance in 2007

        At the beginning of 2007, the Board of Managers requested that Mr. Hinckley provide a general overview of our corporate performance at that time with respect to (i) the development, hedging and construction of the Initial New York Windparks, (ii) the status of our future project development pipeline, and (iii) the status of certain financings to be finalized in 2007. The Board of Managers then developed a general, qualitative projection of where our corporate performance, especially with respect to each of the criteria described above, should be by the end of 2007. At the end of 2007, the Board of Managers evaluated our actual corporate performance in 2007, especially with respect to each of the criteria described above, against its general, qualitative projections or our corporate performance. The Board of Managers determined that progress toward commencing operation of the Initial New York Windparks was made, we met several key development milestones for the New York 2008 windparks and the Great Plains windparks, we advanced future projects' development, and we closed the turbine credit facility, enabling the purchase of wind turbines under turbine supply agreements.

    Individual Contributions to Corporate Performance

        As described below, individual contributions to corporate performance were a factor in the amount of cash bonus that each named executive officer received in 2007. Specifically, the Board of Managers made a subjective determination with respect to each named executive officer concerning whether that

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individual had met the Board's expectations in their respective roles, responsibilities and contributions to the company in 2007. Specifically, the Board determined that:

    Mr. Hinckley managed our ability to move the Initial New York Windparks toward operation, originate and advance the Great Plains project toward a 2008 construction start, advance the 2008 New York windparks toward a 2008 construction start, closed the financing for the Initial New York windparks, and otherwise continued to build our management infrastructure;

    Mr. Quirke managed our ability to complete the development of the Initial New York Windparks, originate the Great Plains project, and move the New York 2008 windparks toward a 2008 construction start;

    Mr. Lowe made significant financial decisions to develop the company and played a critical role in the financial closing of the turbine facility;

    Ms. Grisaru managed the negotiation of regulatory and environmental matters and further developed the company's legal department; and

    Mr. Swank implemented major contracts and created the structure of our hedging strategy for our 2007 and 2008 windparks.

        In assessing the cash bonus amount for Mr. Hinckley, Mr. Hinckley wrote a formal self-evaluation and submitted the evaluation to the Board of Managers. The Board of Managers considered Mr. Hinckley's self-evaluation and the factors listed in the above paragraph to determine the 2007 cash bonus amount for Mr. Hinckley. The process for determining 2007 cash bonus amounts for the other named executive officers followed a similar process to that of Mr. Hinckley. Each named executive officer performed a self-evaluation of performance during 2007 and submitted the evaluation to Mr. Hinckley. Taking under consideration the self-reviews, Mr. Hinckley performed written appraisals of performance for each named executive officer. Based on those appraisals and the corporate performance factors listed in the above paragraph, Mr. Hinckley proposed the bonus amount for each named executive officer to the Board of Managers.

    Market Check of Proposed Annual Bonus Amounts

        The Board of Managers then performed a market check against the analysis prepared by Cook, as further described above in "—Role of the Board of Managers, Executive Officers and Consultants."

    Annual Cash Bonus Determinations

        Based on the factors set forth above, the Board of Managers approved annual cash bonuses for each of the named executives. The amount of the annual cash bonuses are shown below in the "2007 Summary Compensation Table."

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    Long-Term Equity Incentive Compensation

        Historically, we have used our equity-based compensation program as an incentive to recruit and retain executives, to reward outstanding performance and to focus our management on the task of creating long-term stockholder value. Our founding executives, Messrs. Hinckley and Quirke, directly or indirectly own Series A Preferred Units. Messrs. Hinckley and Quirke, along with other named executive officers, also own partially participating Series A Incentive Units and Series A Performance Units.

        Except for the non-compensatory purchases made by Rockfield Noble Holding, LLC as described in "Certain Relationships and Related Party Transactions—Issuances of Equity Interests to Founders and Control Persons, none of the named executive officers purchased Series A Preferred Units, Series A Incentive Units or Series A Performance Units in 2007. In 2008 we offered Mr. Lowe the opportunity to purchase 10,775 Series A Incentive Units and 8,725 Series A Performance Units. Mr. Lowe purchased those Series A Incentive Units and Series A Performance Units in February 2008. All Series A Preferred Units, Series A Incentive Units and Series A Performance Units convert into shares of our common stock as of the date of our corporate reorganization effected by way of a conversion prior to the consummation of this offering, which is further described in "Corporate Reorganization."

        We plan to adopt an equity incentive plan, effective upon the completion of this offering, to further our objectives of recruiting and retaining exceptional executive officers, to give our executive officers an incentive to participate in long-term growth and financial success, and to further align the interests of our executives with our stockholders. Specifically, we will adopt our 2008 Equity Incentive Award Plan, which is further described in "                    ."

    General Benefits

        All of our executive officers are eligible for benefits offered to employees generally, including life, health, disability and dental insurance and our 401(k) plan. These benefits are designed to provide a stable array of support to employees and their families and are provided to all employees regardless of their individual performance levels. In 2007, we continued our historical practice and paid for all medical, dental, vision, life, and disability insurance coverage for all of the named executive officers (and their spouses and dependents, where applicable), including health savings account contributions up to the level of the plan deductibles. We anticipate that, beginning in 2009, we will cease paying for medical, dental, vision, life and disability insurance coverage and health savings account contributions for named executive officers, except under plans and programs offered to all employees generally.

        Additionally, eligible employees may make voluntary contributions to our 401(k) plan up to limits permitted under law, and we may, at our discretion, make profit sharing contributions to our 401(k) plan. All full-time employees who have completed one full calendar month of service are eligible to participate in our 401(k) plan. We made no profit sharing contributions to our 401(k) plan on behalf of the named executive officers in 2007.

    Perquisites

        As a general matter, we do not intend to offer perquisites or other benefits to any executive officer, including the named executive officers, with an aggregate value in excess of $10,000, because we do not believe it is necessary for the attraction or retention of management talent. In 2007, however, we fully reimbursed our named executive officers for all medical, dental, vision, life and disability insurance benefits, as discussed above. We also provided Mr. Hinckley and Mr. Quirke with the use of a company automobile. In 2007, we also offered Mr. Lowe reimbursement of costs incurred for temporary housing for a period of up to 60 days and reimbursement of up to $75,000 for his reasonable relocation expenses, as well as an additional payment for all ordinary income taxes imposed on the

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reimbursements. We reimbursed Mr. Lowe approximately $5,000 for legal fees incurred by him in negotiating his employment agreement with us. In 2007, we reimbursed Mr. Hinckley (through C.C. Hinckley Co, LLC) approximately $20,000 for legal fees incurred by him in negotiating his September 23, 2007 employment agreement.

    Payments upon Termination or Change in Control

        As noted above and further described after the 2007 Grants of Plan-Based Awards table below, we entered into employment agreements or arrangements with each of our named executive officers. All employment agreements or arrangements in effect as of December 31, 2007 (with the exception of our employment arrangement with Mr. Quirke and our employment agreement with Mr. Swank) contain severance provisions, which are important to our compensation philosophy of maximizing long-term stockholder value because (i) they enable us to recruit and retain qualified executives, including named executive officers, by providing competitive terms of employment, and (ii) they provide our executive officers with a measure of stability in compensation, which focuses our executive officers on the task of creating long-term stockholder value through all corporate events. Additional information regarding these severance provisions, including potential payments pursuant to these severance provisions, is provided below under the heading "Potential Payments Made Upon Termination of Employment or Change in Control."

Tax Deductibility of Compensation

        In the review and establishment of our compensation programs, we consider the anticipated accounting and tax implications to us and our executives. While we consider the applicable accounting and tax treatment, these factors alone are not dispositive, and we also consider the cash and non-cash impact of the programs and whether a program is consistent with our overall compensation philosophy and objectives.

        Section 162(m) of the Internal Revenue Code imposes a limit on the amount of compensation that we may deduct in any one year with respect to covered employees, unless specific detailed criteria are satisfied. In general, the compensation we have provided is not subject to the limitations on deductibility under Section 162(m). However, we reserve the right to design programs that recognize a full range of performance criteria important to our success, even where the compensation paid under such programs may not be deductible.

Executive Compensation

        The following table sets forth the compensation paid in 2007 to our principal executive officer, our principal financial officer, our former principal financial officer and each of our three other most highly compensated executive officers who were serving as executive officers on December 31, 2007. These six individuals are sometimes referred to collectively as the "named executive officers."

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2007 Summary Compensation Table

Name and Principal Position

  Year
  Salary
($)

  Bonus
($)

  Non-Equity
Incentive Plan
Compensation
($)(1)

  All Other
Compensation
($)

  Total
($)

Charles Hinckley
Chief Executive Officer(2)
  2007   351,692 (3) 100,000 (4)   38,264 (5) 489,956

Christopher Lowe
Executive Vice President and Chief Financial Officer(6)

 

2007

 

148,846

 


 

240,000

 

24,233

(7)

413,069

Anne Edgley
Former Chief Financial Officer, Senior Vice President, Strategy and Business Operations(8)

 

2007

 

281,520

 


 


 

6,650

(9)

288,170

John Quirke
Executive Vice President, Development

 

2007

 

360,000

(10)


 

100,000

 

14,934

(11)

474,934

Elizabeth Grisaru
Senior Vice President and General Counsel(12)

 

2007

 

306,000

 


 

53,200

 

15,698

(13)

374,898

Thomas Swank
Senior Vice President, Commodities and Risk Management

 

2007

 

300,000

 


 

175,000

 

9,610

(14)

484,610

(1)
This column reflects the amount earned in 2007 by each named executive officer (other than Mr. Quirke) as an annual cash bonus, and by Mr. Quirke as a discretionary payment, as described in "—Annual Cash Compensation, Annual Cash Bonus" in the Compensation Discussion and Analysis. The target amount of annual cash bonus for each named executive officer (other than Mr. Quirke, who did not have a target amount) is further described below in the 2007 Grants of Plan-Based Awards table.

(2)
Mr. Hinckley was our Chief Executive Officer in 2007. In April 2008, he transitioned to the role of Executive Chairman of our Board of Managers.

(3)
C.C. Hinckley Co, LLC received a guaranteed monthly payment of $30,000 through October 2007. Mr. Hinckley entered into an employment agreement with us on September 23, 2007, whereby he was entitled to receive an annual base salary. He began to receive payments of his annual base salary in November 2007, which payments equaled $51,692 in the aggregate.

(4)
This number reflects the guaranteed minimum bonus that Mr. Hinckley was entitled to receive pursuant to his employment agreement with us, dated September 23, 2007.

(5)
Includes $20,008 in reimbursements to C.C. Hinckley Co, LLC for legal fees incurred by Mr. Hinckley in negotiating his September 23, 2007 employment agreement, $12,498 of payments for Mr. Hinckley's medical, dental, vision, life and disability insurance, $3,000 of health savings account contributions made on Mr. Hinckley's behalf and $1,979 in expenses incurred in connection with Mr. Hinckley's use of a company automobile.

(6)
Mr. Lowe commenced his employment with us on June 19, 2007.

(7)
Includes $5,042 in reimbursements for legal fees incurred by Mr. Lowe in negotiating his employment agreement, $12,292 in reimbursements for costs associated with Mr. Lowe's relocation expenses and related lodging expenses, $3,889 of payments for Mr. Lowe's medical, dental, vision,

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    life and disability insurance and $3,000 of health savings account contributions made on Mr. Lowe's behalf.

(8)
Ms. Edgley served as our Chief Financial Officer in the beginning of 2007 and transitioned to the role of Senior Vice President, Strategy and Business Operations in 2007.

(9)
Includes $5,150 of payments for Ms. Edgley's medical, dental, vision, life and disability insurance and $1,500 of health savings contributions made on Ms. Edgley's behalf.

(10)
Mr. Quirke received a guaranteed monthly payment of $30,000 per month in 2007.

(11)
Includes $7,790 of payments for medical Mr. Quirke's medical, dental, vision, life and disability insurance, $3,000 of health savings account contributions made on Mr. Quirke's behalf, $2,042 in expenses incurred in connection with Mr. Quirke's use of a company automobile and $2,102 in payments for Mr. Quirke's wife's cellular telephone.

(12)
Ms. Grisaru served as our General Counsel in 2007 and transitioned to the role of Deputy General Counsel in 2008.

(13)
Includes $12,698 of payments for Ms. Grisaru's medical, dental, life and disability insurance and $3,000 of health savings account contributions made on Ms. Grisaru's behalf.

(14)
Includes $6,610 of payments for Mr. Swank's medical, dental, vision and disability insurance and $3,000 of health savings contributions made on Mr. Swank's behalf.


2007 Grants of Plan-Based Awards

        The following table sets forth information with respect to grants of plan-based awards during 2007 to the named executive officers:

 
  Estimated Possible
Payouts Under
Non-Equity Incentive
Plan Awards(1)

Name

  Target
($)

Charles Hinckley   420,000

Christopher Lowe

 

200,000

Anne Edgley

 

N/A

John Quirke

 

N/A

Elizabeth Grisaru

 

153,000

Thomas Swank

 

250,000

(1)
This column shows the target amount that each named executive officer (other than Mr. Quirke and Ms. Edgley) could have received in annual cash bonuses for 2007, as further described in "—Annual Cash Compensation, Annual Cash Bonus" in the Compensation Discussion and Analysis. Mr. Quirke and Ms. Edgley had no target amounts in 2007. There were no threshold or maximum amounts for the annual cash bonuses (or, in the case of Mr. Quirke, for the discretionary payment) to the named executive officers. The actual amount of annual cash bonus (or, in the case of Mr. Quirke, the discretionary payment) that each named executive officer earned for fiscal year 2007 is set forth in the column titled "Non-Equity Incentive Plan Compensation" in the 2007 Summary Compensation Table above. The annual cash bonus that each named executive officer earned for fiscal year 2007 was paid in January 2008.

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    Employment Agreements

        In 2004, we entered into an employment arrangement with Mr. Hinckley, whereby C.C. Hinckley Co, LLC was entitled to receive a $30,000 guaranteed monthly payment. On September 23, 2007, we entered into an employment agreement with Mr. Hinckley. Employment under the September 23, 2007 agreement extends until December 31, 2008 with successive automatic one-year renewals thereafter, unless either we or Mr. Hinckley gives 90 days' notice of non-extension. Under the employment agreement, Mr. Hinckley is entitled to an annual base salary of $420,000 and an opportunity to earn a bonus based on individual and corporate performance, with a target of 100% of his annual base salary. For the years 2007 and 2008, Mr. Hinckley is entitled to a guaranteed bonus of not less than 25% of his annual base salary, provided that he remains continuously employed by us through the date of payment.

        On June 19, 2007, we entered into an employment agreement with Mr. Lowe. Employment under the agreement extends until June 19, 2010 with successive automatic one-year renewals thereafter, unless either we or Mr. Lowe gives 90 days' notice of non-extension. Under the employment agreement, Mr. Lowe is entitled to an annual base salary of $300,000 and an opportunity to earn a bonus upon fulfilling certain annual goals and objectives set by our Board of Managers or our Chief Executive Officer, with a target of 66.67% of his annual base salary.

        In 2005, we entered into an employment arrangement with Ms. Edgley pursuant to the terms of an offer letter. Under the terms of the offer letter, Ms. Edgley would be employed for an initial term of three years, commencing on October 1, 2005. Under the offer letter, Ms. Edgley was entitled to receive a base salary of $276,000 and an opportunity to earn a bonus based on individual and corporate performance, with no specified target.

        In 2004, we entered into an employment arrangement with Mr. Quirke, whereby he was entitled to receive a $30,000 guaranteed monthly payment, as well as a discretionary amount based on individual and corporate performance.

        On April 17, 2006, we entered into an employment agreement with Ms. Grisaru. Under the employment agreement, Ms. Grisaru is entitled to an annual base salary of $300,000 and an opportunity to earn a bonus upon fulfilling certain annual goals and objectives mutually agreed to by Ms. Grisaru and us, with a target of 25% to 50% of her annual base salary.

        On August 8, 2005, we entered into an employment agreement with Mr. Swank. The initial term of employment ended August 8, 2007. Since the initial term ended, the employment agreement continues on a month-to-month basis. Under the employment agreement, Mr. Swank is entitled to an annual base salary of $300,000 and an opportunity to earn a bonus of $250,000 in 2006 and each year thereafter.

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2007 Outstanding Equity Awards at Fiscal Year-End

        The following table sets forth information with respect to outstanding equity awards of the named executive officers as of December 31, 2007:

 
  Option Awards(1)(2)
  Stock Awards(1)
 
Name

  Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable

  Option
Exercise
Price
($)

  Option
Expiration
Date

  Number
of Shares
or Units
of Stock
That Have
Not Vested
(#)

  Market Value
of Shares
or Units
of Stock
That Have
Not Vested
($)

  Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights
That Have
Not Vested
(#)

  Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights
That Have
Not Vested
($)

 
Charles Hinckley(3)         22,961
1,870
(4)(6)
(4)(7)
2,296
187
(4)
(4)
45,261
1,893
(5)(6)
(5)(7)
4,526
189
(5)
(5)

Christopher Lowe

 


 


 


 


 


 


 


 

Anne Edgley

 

1,000

 

100

 

April 8, 2008

 

2,431

(4)(6)

667

(4)

4,792

(5)(6)

479

(5)

John Quirke(3)

 


 


 


 

22,961
1,870

(4)(6)
(4)(7)

2,296
187

(4)
(4)

45,261
1,893

(5)(6)
(5)(7)

4,526
189

(5)
(5)

Elizabeth Grisaru

 


 


 


 

6,144

(4)(7)

614

(4)

6,218

(5)(7)

622

(5)

Thomas Swank

 

2,500

 

100

 

August 2008

 

4,052

(4)(6)

405

(4)

7,987

(5)(6)

799

(5)

(1)
Series A Incentive Units, Series A Performance Units and Series A Preferred Units will convert into shares of our common stock as of the date or our corporate reorganization following the pricing of this offering as further described in "Corporate Reorganization."

(2)
Options to purchase Series A Preferred Units were granted to Ms. Edgley pursuant to her offer letter and to Mr. Swank pursuant to his employment agreement. Ms. Edgley's options terminated as of the date of her severance agreement. Mr. Swank's options terminate during August 2008.

(3)
Series A Incentive Units and Series A Performance Units were sold to the named executive officer and also to trusts and limited liability companies related to the named executive officer. In the event of the named executive officer's termination of employment, we can repurchase the named executive officer's non-participating units at $0.10 per unit.

(4)
This number represents the Series A Incentive Units that would not be permanently participating units entitled to distributions pursuant to our distribution waterfall in our Second Amended and Restated Limited Liability Company Operating Agreement dated December 21, 2007 (in this section, the "Operating Agreement") if the applicable named executive officer was terminated as of December 31, 2007. Subject to the achievement of a dollar threshold that was achieved prior to December 31, 2007, 20% of the Series A Incentive Units become permanently participating units under the Operating Agreement on the date of issuance, 26.6% become permanently participating units on the second anniversary of the date of issuance and 26.7% become participating on the third and fourth anniversary of the date of issuance, subject to the named executive officer's continued employment on the applicable date. The market value of the Series A Incentive Units was determined by multiplying the number of Series A Incentive Units that were not permanently participating as of December 31, 2007 by the fair market value per Series A Incentive Unit on December 31, 2007.

(5)
This number represents the Series A Performance Units that would not be permanently participating units entitled to distributions pursuant to the Operating Agreement's distribution waterfall if the applicable named executive officer was terminated as of December 31, 2007. Subject to the further achievement of an internal rate of return threshold of at least 30% on JPMP's capital contributions, a 200% return on JPMP's capital contributions and a dollar threshold that was achieved prior to December 31, 2007, 20% of the Series A Performance Units are eligible to become permanently participating units under the Operating Agreement on the date of issuance, 26.6% become permanently participating units on the second anniversary of the date of issuance and 26.7% become participating on the third and fourth anniversary of the date of issuance, subject to the named executive officer's continued employment on the applicable date. The market value of the Series A Performance Units was determined by multiplying the number of Series A Performance Units that

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    were not permanently participating as of December 31, 2007 by the fair market value per Series A Performance Unit on December 31, 2007.

(6)
The Series A Incentive Units and Series A Performance Units were deemed issued on July 1, 2004.

(7)
The Series A Incentive Units and Series A Performance Units were issued on December 30, 2006.


2007 Stock Vested

        No options were exercised by any of the named executive officers during the year ended December 31, 2007. The following table sets forth information with respect to units that became permanently participating units entitled to distributions pursuant to our Operating Agreement's distribution waterfall during 2007:

 
  Stock Awards(1)
Name

  Number of Shares
Acquired on Vesting
(#)(2)

  Value Realized
on Vesting
($)(3)

Charles Hinckley   22,961   2,296
Christopher Lowe    
Anne Edgley   2,431   243
John Quirke   22,961   2,296
Elizabeth Grisaru    
Thomas Swank   4,052   405

      (1)
      Series A Incentive Units and Series A Performance Units will convert into shares of our common stock as of the date or our corporate reorganization following the pricing of this offering as further described in "Corporate Reorganization."

      (2)
      This number represents Series A Incentive Units that became permanently participating units entitled to distributions pursuant to our Operating Agreement's distribution waterfall during the year ended December 31, 2007.

      (3)
      The value realized equals the fair market value per Series A Incentive Unit on the applicable permanent participation date, multiplied by the number of Series A Incentive Units that become permanently participating as of that date.

Potential Payments Upon Termination or Change in Control

        We have summarized below the severance and change in control provisions in the named executive officer employment agreements and arrangements and have shown below the payments and benefits that the named executive officers would have received if, as of December 31, 2007, the named executive officer had experienced a termination of employment with us or we had experienced a change in control.

Employment Agreement with Charles Hinckley

        We entered into an employment agreement with Mr. Hinckley on September 23, 2007. The employment agreement does not provide Mr. Hinckley with any additional payments upon a change in control.

        Pursuant to his employment agreement, in the event that Mr. Hinckley terminates his employment for good reason, we terminate his employment without cause, or Mr. Hinckley experiences a termination of employment due to disability, Mr. Hinckley is entitled to receive: (i) a severance payment equal to twelve months of his base salary, payable in a lump sum ($420,000); (ii) any guaranteed bonus payment that had not yet been paid, which would have equaled 25% of his base

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salary in 2007; (iii) a pro-rated bonus for his year of termination; and (iv) continued coverage under our health and welfare plans for twelve months, including an annual contribution of $4,000 in January and $1,400 each month thereafter, as adjusted from time to time to reflect changes in the costs of such benefits. If Mr. Hinckley's employment with us had terminated on December 31, 2007, then he would have received a total of $420,000 in cash severance and an estimated value of health coverage of $20,420. "Good reason" generally means a material diminution in his compensation, responsibilities, duties, title or authority, a relocation of his place of employment by more than fifty miles or a material violation of his employment agreement.

        Pursuant to his employment agreement, in the event that Mr. Hinckley experiences a termination of employment due to his death, then his estate or representative would be entitled to receive: (i) any guaranteed bonus payment that had not yet been paid, which would have equaled 25% of his base salary in 2007; and (ii) a pro-rated bonus for his year of termination.

        To receive the severance and benefits described above, Mr. Hinckley is required to execute a general release of claims. In addition to executing the release, Mr. Hinckley must comply with non-competition and non-solicitation covenants for one year after his termination of employment, as well as confidentiality, invention assignment and non-disparagement provisions in perpetuity.

Employment Agreement with Christopher Lowe

        We entered into an employment agreement with Mr. Lowe on June 19, 2007. This employment agreement does not provide Mr. Lowe with any additional payments upon a change in control.

        Pursuant to his employment agreement, in the event that Mr. Lowe terminates his employment for good reason, or in the event that we terminate his employment without cause, Mr. Lowe is entitled to receive his annual base salary through June 19, 2009, payable in accordance with normal payroll practices, and continued health coverage for Mr. Lowe and his dependents through June 19, 2009. If Mr. Lowe had terminated his employment with us on December 31, 2007 and been entitled to the severance payments and benefits, then he would have received a total of $437,500 in cash severance and an estimated value of health coverage of $25,500. "Good reason" generally means a material adverse change in his responsibilities, duties or authority, a failure to continue Mr. Lowe as our Chief Financial Officer, a reduction in his base salary, a failure of a successor to assume his employment agreement or a relocation of his place of employment by more than fifty miles or a material breach of his employment agreement.

        To receive the annual base salary described above, Mr. Lowe is required to execute a general release of claims, which includes a non-disparagement clause. In addition to executing the release, Mr. Lowe must comply with confidentiality and invention assignment provisions in perpetuity.

Employment Offer Letter with Anne Edgley

        We sent an employment offer letter to Ms. Edgley in 2005, summarizing certain terms of her employment. For purposes of this disclosure, we have summarized the benefits that Ms. Edgley would have received pursuant to that offer letter and subsequent arrangements as if, as of December 31, 2007, she had experienced a termination of employment or we had experienced a change in control.

        Pursuant to the offer letter, in the event that we had terminated Ms. Edgley's employment for convenience or if we had ceased our business activity as of December 31, 2007, she would have been entitled to receive three months of salary ($70,380) and reasonable costs associated with her relocation back to the United Kingdom (estimated at $11,750).

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Employment Agreement with Elizabeth Grisaru

        We entered into an employment agreement with Ms. Grisaru on April 17, 2006. Except as described below, the employment agreement does not provide Ms. Grisaru with any additional payments upon a change in control.

        Pursuant to her employment agreement, in the event that we terminate the employment of Ms. Grisaru without cause, she is entitled to receive twelve months of her annual base salary, payable in accordance with our normal payroll practices. If pursuant to the previous sentence, Ms. Grisaru's employment with us had terminated on December 31, 2007, then she would have received a total of $306,000 in cash severance. In the event that Ms. Grisaru terminates her employment for any reason within six months following a change in control, which does not include this offering, she is entitled to receive six months of her annual base salary, payable in a lump sum. If pursuant to the previous sentence, Ms. Grisaru's employment with us had terminated on December 31, 2007, then she would have received a total of $153,000 in cash severance.

        To receive the severance and benefits described above, Ms. Grisaru is required to execute a general release of claims. In addition to executing the release, Ms. Grisaru must comply with confidentiality and invention assignment provisions in perpetuity.

Equity Compensation

        As described in "—2007 Outstanding Equity Awards at Fiscal Year-End," each of the named executive officers, except Mr. Lowe, owned both Series A Incentive Units and Series A Performance Units as of December 31, 2007, a number of which were still subject to meeting participation thresholds set forth in our Operating Agreement. The extent to which the Series A Incentive Units and Series A Performance Units achieve their relative participation thresholds under our Operating Agreement determines to what extent such units are entitled to distributions pursuant to our Operating Agreement's distribution waterfall. The Series A Incentive Units and Series A Performance Units participation rates do not increase as a result of a named executive officer's termination of employment. However, subject to the named executive officer's continued employment with us on the date of a change in control, the participation rates for the Series A Incentive Units become 100% participating upon a change in control (as defined in the Operating Agreement) and certain participation rates for the Series A Performance Units increase upon a change in control if the participation threshold based upon a 30% internal rate of return and 200% return for JPMP's capital contributions to us is exceeded. If we experienced a change in control on December 31, 2007, then the participation rates with respect to the Series A Incentive Units would have become 100%, though we do not believe that the Series A Incentive Units would have received any value under the distribution waterfall. The participation rates for the Series A Performance Units would not have increased if we experienced a change in control on December 31, 2007.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Issuances of Equity Interests to Founders and Control Persons

        Between September 2004 and February 2005, we sold preferred units to each of our three founders, Charles Hinckley, John Quirke and Peter Mastic (or to certain entities associated with such persons) at a puchase price of $100 per preferred unit. Between March and December 2006, we sold common units to our founders (or to certain trusts or other entities associated with such persons) at a purchase price of $0.10 per common unit. A summary of these sales is presented in the table below:

Founder

  Number of
Preferred Units

  Number of
Common Units

Charles Hinckley   917   135,487
John Quirke   1,417   135,487
Peter Mastic   1,167   131,257

        In addition, in March 2006, we issued 1,000 preferred units to each of our three founders, at no cost, in consideration of their services in founding and organizing us.

        During 2007, we sold an aggregate of 129,424 preferred units to Rockfield Noble Holding, LLC at a purchase price of $100 per unit, for an aggregate purchase price of $12,942,400. The members of Rockfield Noble Holding include Messrs. Hinckley, Quirke, Mastic and Swank.

        Between September 2004 and February 2008, we sold an aggregate of 3,287,337 preferred units to JPMP Wind Energy (Noble), LLC at a purchase price of $100 per unit, for an aggregate purchase price of $328,733,700.

        In March 2008, we sold 1,100,000 preferred units to CPP Investment Board (USRE II) Inc. at a purchase price of $100 per unit, for an aggregate purchase price of $110,000,000.

Governance Agreements

        In connection with this offering, we and certain of our stockholders (including the sponsors) will enter into a stockholders agreement. This stockholders agreement, together with our certificate of incorporation and bylaws, which we refer to as our governance agreements, will define the rights and obligations of the stockholders party to such agreements following this offering with respect to voting their shares of our common stock on certain matters, corporate governance, registration rights and ownership and transfer of their shares of our common stock.

        The governance agreements will include provisions related to the size and composition of our board of directors, including provisions that will entitle the sponsors to nominate a certain number of directors to our board of directors which shall collectively constitute a majority of our board of directors.

Employment Agreements

        The following describes employment agreements and Change in Control Severance Agreements entered into in 2008 with each of Mr. Howard, Mr. Hinckley, Mr. Quirke and Ms. Mann.

        On May 5, 2008, we entered into an employment agreement with Mr. Howard, which became effective as of that date. The employment agreement reflects the terms of Mr. Howard's employment as our President and Chief Executive Officer as of April 1, 2008. Pursuant to the employment agreement, Mr. Howard is entitled to an initial annual salary of $420,000 and is eligible for an annual bonus with a target of 100% of his annual salary. Mr. Howard is also entitled to a one-time sign-on bonus of $35,000. During his term of employment, Mr. Howard is eligible to participate in employee benefits plans, programs, and arrangements available to similarly-situated employees, and Mr. Howard

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is entitled to the use of an automobile provided by us, in accordance with our automobile policy. During his term of employment and thereafter, Mr. Howard is entitled to coverage under our directors' and officers' liability insurance policy. Mr. Howard is eligible to receive reimbursement for a maximum of $15,000 in relocation expenses, for a maximum of three months of executive housing, and for a maximum of $20,000 in legal fees incurred prior to May 5, 2008 in connection with the negotiation or review of the employment agreement. The employment agreement also sets forth the understanding that after May 5, 2008, we intend to grant Mr. Howard the opportunity to purchase 2,599 Series A Incentive Units, 5,944 Series A Performance Units, 58,889 Series B Incentive Units and 29,445 Series B Performance Units, contingent on his remaining employed by us as of the date of the grant. In addition to the compensation and benefits described in this paragraph, the employment agreement provides for certain payments to be made to Mr. Howard upon termination of employment. For a description of these terms, see "—Termination Payments" below.

        On May 5, 2008, we entered into a new employment agreement with Mr. Hinckley, which is effective as of that date. The new employment agreement supersedes our prior employment agreement with Mr. Hinckley, dated as of September 23, 2007, which is summarized in "—Executive Compensation, Employment Agreements." The new employment agreement reflects the terms of Mr. Hinckley's employment in his new position as Executive Chairman of our Board of Managers (or our Board of Directors, after the completion of this offering) as of April 1, 2008. Pursuant to the employment agreement, Mr. Hinckley is entitled to an initial annual salary of $360,000 and is eligible for an annual bonus with a target of 67% of his annual salary. Mr. Hinckley is entitled to receive a one-time bonus of $150,000 in consideration of his agreeing to terminate his prior employment agreement. If Noble completes this offering, Mr. Hinckley will also be entitled to receive a one-time bonus equal to $150,000 in restricted stock, which stock will be subject to our 2008 Equity Incentive Award Plan and the accompanying restricted stock award agreement, and which shares shall be calculated using the public offering price per share indicated on the cover of this prospectus. During his term of employment, Mr. Hinckley is also eligible to participate in employee benefits plans, programs and arrangements available to similarly-situated employees, and Mr. Hinckley is entitled to the use of an automobile provided by us, in accordance with our automobile policy. During his term of employment and thereafter, Mr. Hinckley is entitled to coverage under our directors' and officers' liability insurance policy. Mr. Hinckley is eligible to receive reimbursement for a maximum of $10,000 in legal fees incurred prior to May 5, 2008 in connection with the negotiation and review of the employment agreement. The employment agreement also sets forth the understanding that after May 5, 2008, we intend to grant Mr. Hinckley the opportunity to purchase 35,541 Series B Incentive Units and 17,771 Series B Performance Units, contingent on his remaining employed by us as of the date of the grant. In addition to the compensation and benefits described in this paragraph, the employment agreement provides for certain payments to be made to Mr. Hinckley upon termination of employment. For a description of these terms, see "—Termination Payments" below.

        On May 5, 2008, we entered into an employment agreement with Mr. Quirke, effective as of that date. The employment agreement reflects the terms of Mr. Quirke's employment as our Executive Vice President, Development. Under the employment agreement, Mr. Quirke is entitled to an initial annual salary of $360,000 and an opportunity to earn an annual bonus with a target of 67% of his annual salary. During his term of employment, Mr. Quirke is also eligible to participate in employee benefits, plans, programs and arrangements available to similarly-situated employees. The employment agreement also sets forth the understanding that after May 5, 2008, we intend to grant Mr. Quirke the opportunity to purchase 35,541 Series B Incentive Units and 17,771 Series B Performance Units, contingent on his remaining employed by us as of the date of the grant. In addition to the compensation and benefits described in this paragraph, the employment agreement provides for certain payments to be made to Mr. Quirke upon termination of employment. For a description of these terms, see "—Termination Payments" below.

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        On May 5, 2008, we entered into an employment agreement with Ms. Mann, which became effective as of that date. The employment agreement reflects the terms of Ms. Mann's employment as our Senior Vice President, General Counsel and Secretary. Pursuant to the employment agreement, Ms. Mann is entitled to an initial annual salary of $315,000 and is eligible for an annual bonus with a target of 50% of her annual salary. Ms. Mann is entitled to a guaranteed minimum bonus of $100,000 for 2008, provided that Ms. Mann remains employed by us until the date on which annual bonuses for 2008 are paid to similarly-situated employees, or provided that we terminate Ms. Mann's employment without cause prior to that date. During her term of employment, Ms. Mann is eligible to participate in employee benefits plans, programs, and arrangements available to similarly-situated employees. Ms. Mann is eligible to receive reimbursement for a maximum of $60,000 in relocation expenses, which Ms. Mann agrees to repay if she resigns or if we terminate her employment for cause before May 5, 2009. The employment agreement also sets forth the understanding that after May 5, 2008, we intend to grant Ms. Mann the opportunity to purchase 10,000 Series B Incentive Units and 5,000 Series B Performance Units, contingent on her remaining employed by us as of the date of the grant. In addition to the compensation and benefits described in this paragraph, the employment agreement provides for certain payments to be made to Ms. Mann upon termination of employment. For a description of these terms, see "—Termination Payments" below.

Termination Payments

Payments under the Employment Agreements

        The employment agreements for each of Mr. Howard, Mr. Hinckley, Mr. Quirke and Ms. Mann provide for the payment of severance benefits to the executive if we terminate the executive's employment without cause or, in the case of Mr. Howard and Mr. Hinckley, in the event they terminate for "good reason." Upon such termination, the executive will be entitled to receive (i) a cash amount equal to six months' salary and (ii) reimbursement for up to six months of the employer's portion of health coverage premiums.

        The employment agreements for each of Mr. Howard and Mr. Hinckley also provide that if they are terminated without cause or resign for good reason, they will be entitled to receive a cash amount equal to a prorated portion of their respective annual bonuses for the performance period in which they incur a termination of employment, which amount will be calculated based on our performance for the entirety of the performance period. "Good reason" in Mr. Howard's and Mr. Hinckley's employment agreements and the Change in Control Severance Agreements described below generally means (i) a material reduction in salary, (ii) a relocation of the executive's principal place of employment by more than 50 miles, (iii) for Mr. Howard, a material and adverse reduction in duties, responsibilities or authority and, for Mr. Hinckley, a material and adverse reduction in duties or (iv) only under the Change in Control Severance Agreements described below, the failure of a successor to assume the Change in Control Severance Agreement.

Change in Control Severance Agreements

        On May 5, 2008, we entered into Change in Control Severance Agreements with each of Mr. Howard, Mr. Hinckley, Mr. Quirke and Ms. Mann. In general, the Change in Control Severance Agreements provide severance benefits to the executive if we terminate his or her employment without cause or if the executive resigns his or her employment for "good reason" during the period commencing as of the date of our change in control, which does not include this offering, and ending 12 months later. In the event an executive is entitled to a payment under a Change in Control Severance Agreement, he or she is not entitled to severance benefits under his or her employment agreement. The term of each Change in Control Severance Agreement commences on the date that we complete this offering and ends on the first anniversary of the offering. "Good reason" in Mr. Quirke's and Ms. Mann's Change in Control Severance Agreements generally means (i) a relocation of the

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executive's principal place of employment by more than 50 miles, (ii) a material and adverse reduction in authority or title or (iii) for Ms. Mann, a change that requires her to report to someone other than the Chief Executive Officer.

        Pursuant to the terms of the Change in Control Severance Agreements for Mr. Howard and Mr. Hinckley, upon a termination of employment described above, Mr. Howard or Mr. Hinckley will be entitled to receive (i) a cash amount equal to twelve months of salary, (ii) a cash amount equal to a prorated portion of the annual bonus to which Mr. Howard or Mr. Hinckley would have been eligible to receive for the performance period in which Mr. Howard or Mr. Hinckley incurred a termination of employment, which amount will be calculated based on our performance for the entirety of the performance period, and (iii) reimbursement for up to twelve months of the employer's portion of health coverage premiums. In addition to the severance benefits described in this paragraph, in the event of any legal proceeding relating to the Change in Control Severance Agreements for Mr. Howard or Mr. Hinckley, we will be responsible for paying a maximum of $10,000 of attorneys' fees incurred in connection with such proceeding, provided, however, that Mr. Howard or Mr. Hinckley will reimburse us for such attorneys' fees if either Mr. Howard or Mr. Hinckley, as applicable, does not materially prevail in such proceeding. Mr. Quirke and Ms. Mann are entitled to the same severance benefits under the Change in Control Severance Agreement as they are entitled to under the employment agreement and described above.

        In the event that the amounts payable to any executive under the Change in Control Severance Agreement, together with the amounts payable under any other plan maintained by us, would constitute an "excess parachute payment" within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended, the payments under the Change in Control Severance Agreement will be reduced until no amount payable constitutes an "excess parachute payment." However, this reduction will not be made if the net after-tax payment to the executive if such reduction had not been made would be greater than the net after-tax payment to the executive if such reduction had been made.

Release and Restrictive Covenants

        Each employment agreement and Change in Control Severance Agreement provides that in order for an executive to receive any severance benefits under the agreements, the executive must execute a general release of claims arising under the employment agreement or Change in Control Severance Agreement within 30 days following termination of employment.

        Each employment agreement and Change in Control Severance Agreement includes non-competition covenants applicable to the executive for 6 months following termination of employment for any reason (except as described below) and non-solicitation covenants applicable to the executive for 12 months following termination of employment for any reason.

        The Change in Control Severance Agreements for Mr. Howard and Mr. Hinckley and the employment agreement for Mr. Hinckley provides additional time for non-competition covenants. Pursuant to the Change in Control Severance Agreements for Mr. Howard and Mr. Hinckley, non-competition covenants are applicable for 12 months following termination of employment for any reason. Pursuant to the employment agreement for Mr. Hinckley, we have the right to extend the time period during which the non-competition covenants apply for a maximum of six additional months after the initial six month non-compete period. To exercise that right, we must provide Mr. Hinckley with the following payments for each additional month: (i) a cash amount equal to one month of his salary; and (ii) reimbursement for the employer's portion of health coverage premiums for one month. We must exercise this right within 30 days after Mr. Hinckley incurs a termination of employment and must specify in writing the number of months to which the extension shall apply.

        In addition, each of the employment and Change in Control Severance Agreements with each of the executives provides that all confidential information that the executive has access to, uses or creates

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during his employment and all intellectual property resulting from work done by him on our behalf is our property. Each of the agreements also includes customary confidentiality provisions and non-disparagement provisions.

Other Transactions

        On March 15, 2007, we entered into an employment agreement with Andrew Hinckley, the brother of Charles Hinckley, our Executive Chairman and former Chief Executive Officer. Pursuant to the employment agreement, Andrew Hinckley received a salary and bonus of $177,941 in 2007.

        On March 31, 2008, we entered into a new employment agreement with Andrew Hinckley, which terminated our previous employment agreement with him. Pursuant to the 2008 employment agreement, Mr. Hinckley is employed as our Director, Business Development at an annual base salary of $165,000. In addition to his base salary, Mr. Hinckley is also entitled to success fees based on the successful development of certain of our windparks identified in his employment agreement. The success fees range from $12,500 to $100,000 for each windpark, with possible payments totaling $456,000. For each windpark, Mr. Hinckley is entitled to receive (i) one-third of the success fee upon closing of construction financing of the subject project, or in the event construction financing is not obtained, upon full release for construction of the subject project; (ii) one-third upon term conversion of the financing for the subject project or, in the event term financing is not obtained, upon commercial operation of the subject project; and (iii) one-third 180 days following the date identified in (ii) above. Mr. Hinckley is also entitled to participate in employee benefit plans, programs and arrangements which are applicable to other similarly situated employees.

        We or Mr. Hinckley may terminate the employment agreement, with or without cause, with 90 days' prior written notice or 90 days' base pay in lieu of written notice. If we terminate Mr. Hinckley's employment for cause, as defined in the agreement, neither the 90 days' written notice nor the 90 days' base pay is required. If we terminate Mr. Hinckley's employment without cause, Mr. Hinckley is entitled to receive his base salary until the earlier of 90 calendar days following the last day of his employment with us, or such time that Mr. Hinckley begins employment with another employer, establishes his own business, or works as a consultant for another entity.

        In January 2008, we entered into a compensation arrangement with Barry Goldstein, an independent director. Pursuant to this arrangement, Mr. Goldstein is entitled to receive annual board of managers member cash compensation of $40,000 and annual committee member compensation of $10,000. He will also be offered the opportunity to purchase common units.

Policies and Procedures for Related Party Transactions

        As a public company, we will ensure that all transactions with related parties are fair, reasonable and in our best interest. In this regard, our independent directors or one of our committees comprised of independent directors will review material transactions between us and related parties to determine that, in their best business judgment, such transactions meet that standard.

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PRINCIPAL STOCKHOLDERS

        The following table provides certain information regarding the beneficial ownership of our outstanding common stock after giving effect to our corporate reorganization for:

    each person or group who beneficially owns more than 5% of our outstanding common stock;

    each of our named executive officers;

    each of our directors; and

    all of our directors and executive officers as a group.

        The percentage of ownership indicated before this offering is based on           shares of common stock outstanding after giving effect to our corporate reorganization. The percentage of ownership indicated after this offering is based on           shares, including the shares offered by this prospectus and assuming no exercise of the underwriters' option to purchase additional shares from us and no exercise of options outstanding after                , 2008.

        Beneficial ownership of shares is determined under the rules of the Securities and Exchange Commission and generally includes any shares over which a person exercises sole or shared vot