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As filed with the Securities and Exchange Commission on August 29, 2008

Registration No. 333-150757



SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

AMENDMENT NO. 3
TO
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


*
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.

23,437,500 Shares

GRAPHIC

Noble Environmental Power, Inc.

Common Stock


We are offering 23,437,500 shares of our common stock in this initial public offering. No public market currently exists for our common stock.

We have applied 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 14.

 
  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 3,515,625 shares from us on the same terms and conditions as set forth above to the extent the underwriters sell more than 23,437,500 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   CITI

                      , 2008


GRAPHIC



TABLE OF CONTENTS

 
  Page
Prospectus Summary   1
Risk Factors   14
Special Note Regarding Forward-Looking Statements   35
Industry and Market Data   36
Corporate Reorganization   36
Use of Proceeds   37
Dividend Policy   38
Capitalization   39
Dilution   41
Selected Consolidated Financial Data   43
Management's Discussion and Analysis of Financial Condition and Results of Operations   45
Description of Certain Financing Arrangements   73
Industry Overview   90
Business   101
Management   129
Certain Relationships and Related Party Transactions   154
Principal Stockholders   164
Description of Capital Stock   167
Shares Eligible for Future Sale   170
Certain United States Federal Income Tax Considerations to Non-United States Holders   172
Underwriting   176
Legal Matters   184
Experts   184
Where You Can Find More Information   184
Glossary of Selected Industry Terms   185
Index to Financial Statements   F-1

        You should rely only on the information contained in this prospectus and any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you. 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 consolidated 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 an independent 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 programs and active renewable energy certificate markets. Through renewable portfolio standard programs and renewable energy certificate 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 power generation sales 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 179 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 3,851 MW of capacity as we further expand into attractive wind energy markets in Maine, Michigan, Minnesota, New Hampshire, Pennsylvania, 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 sites for potential 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 currently have contracts in place with General Electric, or GE, to purchase all of the turbines required for all of our windparks slated for construction through 2009 as well as turbines representing 71% of the MW needed to support our windparks slated for construction in 2010. We believe that our performance under the five turbine supply agreements that we have entered into with GE (representing a total of 1,815.0 MW of turbines) strengthens our ability to obtain additional turbines for 2010 and subsequent years.

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        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 existing turbine supply agreements provide us with the knowledge and resources necessary to rapidly grow our windpark portfolio.


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 1,204 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 windparks slated for construction through 2009 as well as turbines representing 71% of the MW needed to support our windparks slated for construction in 2010.

        For many 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 renewable energy certificate 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

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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.

        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
       

Windparks Under Construction

 

 

 

 
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 / Villenova   NY   94.5
Centerville / Rushford   NY   100.5
Chateaugay II   NY   19.5
Great Plains II   TX   126.0
Mitchell County I (Phase I)   TX   159.0
       
Expected Capacity Subtotal       499.5
       
2010 Windparks        
Burke   NY   60.0
Farmersville   NY   100.5
Mitchell County I (Phase II)   TX   141.0
Mitchell County II   TX   150.0
Grandpa's Knob   VT   50.0
Granite Reliable(2)   NH   74.0
Flat Hill I   MN   129.0
       
Expected Capacity Subtotal       704.5
       

Total Expected Capacity Through 2010

 

 

 

1,951.0
       

2011 / 2012 Windparks

 

 

 

 
Expansions of existing windparks       270.0
New windparks in existing states       910.0
Windparks in new states       720.0
       
Estimated Capacity Subtotal       1,900.0
       

Total Estimated Capacity through 2012

 

 

 

3,851.0
       

(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 14 of this prospectus.

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

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Market Opportunity

        From its beginnings in California, wind energy in the U.S. has expanded steadily to 36 of the 50 states. Additionally, the total capacity of U.S. windparks increased by over 680% from 2,500 MW to over 19,500 MW between December 1999 and June 2008. Despite this growth, wind energy generation still only represented just under 1% of U.S. electricity supply in 2007, 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 renewable portfolio standard programs, as well as federal tax incentives including production tax credits 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 37 professionals engaged in activities including site selection, market analysis, land acquisition, community relations and permitting. We also have significant engineering and construction and operations and maintenance expertise, through our combined teams of 76 employees.

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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 15 years of experience with complex power and infrastructure 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 15 years of experience and involvement in bringing domestic and international power and infrastructure projects online, from initial development through financing to ongoing operations and maintenance.

All of the turbines secured to support our windparks slated for construction through 2009 and turbines secured representing 71% of the MW needed to support our windparks slated for construction in 2010

        Our turbine procurement strategy is focused on maintaining relationships with turbine suppliers who have proven track records, access to supply chain materials and experienced installation, service and support personnel. We have successfully secured the turbines needed to support our windparks slated for construction through 2009 as well as turbines representing 71% of the MW needed to support windparks slated for construction in 2010 from GE. With over 8,500 1.5 MW wind turbines installed worldwide, we believe GE turbines have an established track record and a solid history of reliability. We believe that our performance under the five turbine supply agreements that we have entered into with GE (representing a total of 1,815.0 MW of turbines), combined with the fact that a GE subsidiary is a tax equity investor in our Initial New York Windparks and will be a tax equity investor in our Altona, Chateaugay and Wethersfield windparks that are currently under construction in New York, and the number of members of our management team who were previously employed by GE, will strengthen our ability to enter into turbine supply agreements with GE on acceptable terms in the future. In addition to GE, we maintain an active dialogue with Vestas Wind Systems A/S, or Vestas, and as we continue to grow our portfolio, we plan to develop additional relationships with other major turbine suppliers. We believe that our existing turbine supply agreements, increasing scale and experience will enable us to continue to secure the turbines necessary to support our growth.

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.

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Challenges and Risks

        There are substantial challenges and risks that may affect our financial and operating performance and our growth, including:

Our limited operating history and our history of operating losses and negative cash flows from investing activities

        We have a limited operating history from which you can evaluate our business. In addition, from our inception we have incurred net losses and negative cash flows from investing activities. We have spent, and expect to continue to spend, significant resources to fund the development and construction of our windparks and 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.

Our dependence on the continued and uninterrupted operation of a limited number of operating windparks

        We currently have only three windparks in operation, and 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. In addition, since all of our currently operating windparks are located in New York State, any adverse change in the New York regulatory environment or energy market characteristics could impact our operations.

Our dependence on federal tax benefits and state regulatory benefits for renewable energy generation

        We rely on federal tax incentives applicable to the wind energy industry including the production tax credit and state policies and regulatory frameworks that support windpark development, such as renewable portfolio standard requirements. Currently, the production tax credit is scheduled to expire on December 31, 2008. If the federal production tax credit 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. Similarly, the elimination of, or reduction in state government policies that support renewable energy could have an adverse impact on our future development efforts.

Our ability to successfully implement our windpark development plans, raise necessary financing and successfully operate our windparks

        We may not accomplish, or accomplish on a timely basis, some or all of our windpark development milestones including 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, and interconnection agreements and financial commodity hedges or power purchase arrangements. 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. Market conditions and other factors, however, may not permit future financings on terms similar to those we have obtained to date or at all.

The occurrence of delays and cost overruns in the development and construction of our windparks

        We experienced delays in the completion of the Initial New York Windparks and the total construction cost of these windparks exceeded our initial budget. Future construction delays and construction costs in excess of our budgets could prevent us from completing construction of a windpark and cause defaults under our financing and revenue agreements. In addition, significant construction delays may also result in the loss of revenues expected to be generated by our windparks.

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

The vulnerability of our windparks to adverse 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. Our wind resource projections may not predict the actual wind resources experienced by the windpark over a long period of time. In addition, 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.

        In addition, you should carefully consider all of the risks discussed in "Risk Factors," which begins on page 15.

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 renewable portfolio standard 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 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.

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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 power generation sales 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 in advance of the closing of financing for a windpark allows us to potentially benefit from future energy price movements and avoid the cost and price competition involved in bidding on power purchase agreements.

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 use tax equity financing arrangements in order to monetize the value generated by the production tax credits and accelerated tax depreciation that are available to us as a wind energy generator. We are 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.

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Our Sponsors

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

        J.P. Morgan Partners, LLC is a private equity division of JPMorgan Chase & Co. (NYSE: JPM), one of the largest financial institutions in the United States. J.P. Morgan Partners, LLC 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 J.P. Morgan Partners, LLC 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 J.P. Morgan Partners, LLC on its portfolio of private equity investments, including the investment by JPMP in Noble.

        The CPP Investment Board 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 CPP Investment Board is investing in publicly-traded stocks, private equities, real estate, inflation-linked bonds, infrastructure and fixed income. Based in Toronto, Canada, the CPP Investment Board 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 up to five directors (out of a total of up to 10 initial board members), and CPPIB will have the right to designate up to two directors. JPMP's right to designate directors will be increased to up to six directors upon the appointment of a third independent director. 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.

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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.

10



The Offering

Common stock offered by Noble Environmental Power, Inc.    23,437,500 Shares

Common stock outstanding following the offering

 

                 Shares

Underwriters' option to purchase additional shares

 

3,515,625 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 6,800,000 shares that are reserved for issuance pursuant to our incentive award 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.

11



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 six months ended June 30, 2008 and 2007 from our unaudited condensed consolidated financial statements included elsewhere in this prospectus. We have derived the summary consolidated financial data as of and for the years ended December 31, 2007, 2006 and 2005 from our audited consolidated financial statements included elsewhere in this prospectus. We have derived the summary consolidated financial data as of and for the period ended December 31, 2004 from our unaudited consolidated financial statements that are not included in this prospectus.

        Pro forma net income (loss) per share is based on the weighted average common units outstanding. Pro forma net income (loss) per share is computed as if the conversion into a Delaware corporation occurred at the beginning of 2007 and we had been taxed as a C corporation.

        The pro forma information included in the table below as of June 30, 2008 represents our balance sheet and 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 1,000,000 shares of undesignated preferred stock and the automatic conversion of all of our outstanding limited liability company 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 23,437,500 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.

 
  Six Months Ended
June 30,

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

 
 
  2008
  2007
  2007
  2006
  2005
 
 
  (in thousands, except for unit and per unit amounts)
 
Revenues:                                      
  Revenues   $ 3,904   $   $   $   $   $  
  Risk management activities related to operating projects     (33,378 )                    
   
 
 
 
 
 
 
Total revenues     (29,474 )                    

Cost of revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Windpark operating expenses     1,002                      
  Depreciation and amortization     4,145                      
   
 
 
 
 
 
 
Total cost of revenues     5,147                      
   
 
 
 
 
 
 
Gross profit (loss)     (34,621 )                    

Expenditures:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  New project development     1,615     1,763     3,625     2,241     10      
    Salaries, wages, employment taxes and fringe benefits     8,166     4,695     10,627     9,788     2,919     352  
    Other general and administrative expenses     7,546     2,904     8,265     4,024     4,771     733  
   
 
 
 
 
 
 
  General and administrative expenses     15,712     7,599     18,892     13,812     7,690     1,085  
  Depreciation     675     339     776     492     83      
  Write-down of assets held for sale and construction in progress     14,910     391     574     5,500          
  Other (income) expense         (15 )   32     18          
   
 
 
 
 
 
 
Total expenditures     32,912     10,077     23,889     22,063     7,783     1,085  
   
 
 
 
 
 
 
Loss from operations     (67,533 )   (10,077 )   (23,889 )   (22,063 )   (7,783 )   (1,085 )
  Risk management activities related to non-operating projects     (85,773 )   888     (21,073 )            
  Other income     146                      
  Interest expense     (2,568 )                            
  Interest income     1,753     694     2,486     1,384     24      
  Provision for income taxes                          
   
 
 
 
 
 
 
Net loss   $ (153,975 ) $ (8,495 ) $ (42,486 ) $ (20,679 ) $ (7,759 ) $ (1,085 )
   
 
 
 
 
 
 

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Net loss allocable to common unitholders:                                      
  Net loss   $ (153,975 )   (8,495 )   (42,486 )   (20,679 )            
  Preferred dividend(1)     16,408     8,053     18,662     4,017              
   
 
 
 
             
  Net loss allocable to common unitholders   $ (170,383 ) $ (16,548 ) $ (61,148 ) $ (24,696 )            
   
 
 
 
             
Net loss allocable to common unitholders per unit:                                      
  Basic and diluted   $ (353.03 ) $ (35.72 ) $ (131.99 ) $ (69.49 )            
   
 
 
 
             
  Weighted average units used in the calculation of net loss per unit allocable to common unitholders basic and diluted     482,627     463,260     463,260     355,378              
   
 
 
 
             
Pro forma net loss data (unaudited):                                      
  Net loss allocable to common unitholders as reported   $ (170,383 ) $ (16,548 ) $ (61,148 )                  
  Pro forma adjustment for income tax benefit     N/A                            
   
 
 
                   
  Pro forma net loss allocable to common unitholders   $ (170,383 ) $ (16,548 ) $ (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   $ 27,352   $ (11,267 ) $ 39,921   $ (20,210 ) $ (6,036 ) $ (1,003 )
  Cash flows used by investing activities     (567,247 )   (164,490 )   (617,867 )   (507,141 )   (47,206 )    
  Cash flows provided by financing activities     517,651     206,711     618,043     532,591     54,375     1,359  

(1)
The preferred dividend was not declared (or paid) during the period from August 31, 2004 (date of inception) to June 30, 2008.
 
 
  As of June 30, 2008
 
  Actual
  Pro Forma
  Pro Forma
As Adjusted

 
  (in thousands)
Balance sheet data:                  
Cash and cash equivalents   $ 24,582   $     $  
Restricted cash—current     243,801            
Accounts receivable     2,873            
Prepaid and other current assets     2,682            
Assets held for sale     92,114            
Property and equipment, net     623,685            
Construction in progress     752,460            
Restricted cash—long term     18,608            
Construction material deposits     176,486            
Deferred financing costs     11,190            
Derivatives     5,207            
Other assets     3,176            
   
 
 
Total assets   $ 1,956,864            
   
 
 

Short-term liabilities

 

$

360,413

 

 

 

 

 

 
Long-term obligations     1,326,880            
   
 
 
Total liabilities     1,687,293            
   
 
 
Members' equity     269,571            
   
 
 
Total liabilities and equity   $ 1,956,864            
   
 
 

13



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 until recently have operated as a development stage enterprise.

        We were a development stage enterprise from August 31, 2004 (date of inception) until May 13, 2008 at which time we began generating revenue from the sale of electricity. 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:

    refinance our construction 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 generated limited revenue and have generated net losses and negative cash flows from investing activities since our inception.

        For the six months ended June 30, 2008 we generated limited revenue, and we did not generate revenue for the years ended December 31, 2007, 2006 and 2005. During these periods, we also incurred net losses of approximately $154.0 million, $42.5 million, $20.7 million and $7.8 million, respectively, and our net cash used by investing activities was approximately $567.2 million, $617.9 million, $507.1 million, $47.2 million, respectively. At June 30, 2008, our accumulated deficit was approximately $226.0 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.

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        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 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 production tax credit and accelerated tax depreciation for certain windpark assets. The production tax credit 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 20 year depreciable lives of many non-renewable energy assets.

        Currently, the production tax credit 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 production tax credit 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 production tax credit 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 production tax credit is not extended or renewed, or is extended or renewed at a lower rate, our ability to use tax equity financing structures would be impaired or eliminated. As a result, our financing options would be reduced, our financing costs would increase and our development plans for additional windparks would be adversely affected.

15


        Even if the federal production tax credit is extended, we currently expect that we will not have sufficient taxable income to utilize the benefits generated by the federal production tax credit 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 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 places certain limits on our project subsidiaries' operational flexibility and our rights to the cash flow generated by the windparks.

        We 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 is 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 provides that for a period of time, all of the cash flows from the windpark are to 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.

        Currently, we have 29 identified windparks at various stages of development. 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 remain 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.

16


        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.

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 renewable portfolio standard 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 renewable portfolio standard 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.

An ongoing investigation by the New York Attorney General could have a material adverse effect on our business, financial condition and results of operations.

        We and another wind energy company developing windparks in upstate New York recently were served with civil subpoenas by the New York Attorney General relating to an investigation of our and their activities in the State of New York. The Attorney General has publicly indicated that the investigation was prompted by certain complaints of improper dealings with public officials and anti-competitive practices. The investigation being conducted by the New York Attorney General is at an early stage, and we are in the process of responding to the broad requests in the subpoena with the assistance of outside counsel. We currently are unable to anticipate when the investigation may conclude, what further proceedings may follow the investigation, if any, or what impact the investigation or any future additional proceedings may have on our business, our development plans or our ability to obtain financing. The investigation could divert our management's attention and resources. There may be a number of unfavorable outcomes or developments relating to the investigation and any additional proceedings, including monetary sanctions or penalties, injunctions or other punitive remedies, any of which, individually or in the aggregate, could result in a material adverse effect on our business, financial condition or results of operations.

Our high levels of indebtedness could adversely affect our business.

        We have high levels of indebtedness. As of June 30, 2008, we had approximately $1,241.3 million of total consolidated indebtedness, of which approximately 79% 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 renewable energy certificates, as well as the monetization of certain federal tax benefits available to us.

17


        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."

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

18



to purchase all of the required wind turbines for all of our windparks slated for construction through 2009 as well as turbines representing 71% of the MW needed to support our windparks slated for construction in 2010. However, we have not yet contracted for the remaining turbines representing 29% of the MW needed for our 2010 windparks or for turbines for our windparks in development for 2011 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.

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 as well as the availability of grid connection capacity. We also compete for the limited supply of wind turbines, spare parts 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 power generators 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, and 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,

19



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 29 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 renewable energy certificate market prices or liquidity that materially impacts our projected revenues;

    unexpected environmental issues;

    local community opposition to our proposed windparks;

    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;

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    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.

        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 renewable energy certificates 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 renewable energy certificates for the state of New York. Pursuant to our contracts with NYSERDA regarding our Altona, Bellmont and Chateaugay windparks currently in construction, our ability to sell the renewable energy certificates generated by our operation of these windparks may expire if the windparks are not in operation by November 2008.

        In addition, if the production tax credit is not extended to windparks placed in service after December 31, 2008, and construction delays prevent our windparks slated for construction in 2008 from being completed on or before that date, these windparks will not be entitled to the production tax credit.

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. 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 is the source of substantially all of our revenues. As a result, our results of operations are 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.

        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.

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        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;

    our energy hedging arrangements may be adversely affected;

    to the extent that we have entered into agreements for the sale of renewable energy certificates 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 renewable energy certificates;

    we will be entitled to fewer production tax credits than projected, which could 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;

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    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. To date we have secured 81% of the overall land needed to complete our windparks that are in development for construction through 2012. 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.

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

        We depend on electric transmission facilities owned and operated by third parties to deliver the electricity that we 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.

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        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 the Federal Energy Regulatory Commission, or 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.

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 renewable

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energy certificates 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 only recently 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 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 FERC and independent system operators or regional transmission operators, 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.

The price at which we can sell renewable energy certificates 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 renewable energy certificates at fixed prices under existing agreements with NYSERDA, portions of the renewable energy certificates 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 renewable energy certificates to NYSERDA from our Altona, Bellmont and Chateaugay windparks could be terminated if those windparks are not in operation by November 2008. Any increases in the market supply of renewable energy certificates or changes in state and federal regulatory policy may decrease our ability to sell renewable energy certificates in the volumes we forecast or could reduce the sales price of our renewable energy certificates.

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Our hedging strategy may not adequately minimize market risk, may create fluctuations in the revenues and net income (loss) reported on our statement of operations 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 for our Initial New York Windparks and our hedging agreement with Citigroup Energy Inc. for our Altona, Chateaugay and Wethersfield windparks, 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. Our hedging activities may also result in fluctuations in our reported revenues and net income (loss). For example, for the six months ended June 30, 2008, our reported revenues was reduced by a non-cash charge relating to our hedging activities for our operating windparks of $33.2 million. During the six months ended June 30, 2008, we also reported a non-cash charge of $85.1 million relating to our hedging activities for our windparks while they were under construction during the six-month period ending June 30, 2008. 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 LIBOR. We manage interest rate fluctuation risk on our project financing debt by entering into long-term interest rate swaps, which, at June 30, 2008, had a notional value of $309.1 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 Initial New York 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 Initial New York 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 agreements for our Initial New York Windparks, 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

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process ensures a role for concerned members of the public that can lead to changes in design or 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.

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        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 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 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, and exempt wholesale generators are exempt from FERC access to books and records under PUHCA. In order to obtain exempt wholesale generator 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 qualifying facility 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 qualifying facility status with, or has received a qualifying facility certification order from, FERC. A wind generation facility may qualify as a small power production qualifying facility if it is less than 80 MW net capacity. Our Noble Great Plains windpark in Texas is comprised of three small power production qualifying facilities.

        While each of the Initial New York Windparks and our Noble Great Plains windpark has filed a self-certification with FERC that it is an exempt wholesale generator, there is no guarantee that regulatory or other changes will not result in the loss of such exempt wholesale generator 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 regional transmission operator and independent system operators, 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.

        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 Securities and Exchange Commission and The NASDAQ Stock Market impose a number of compliance requirements on us once we become a public company. Our management and other personnel will need to devote a substantial amount of time to these compliance requirements. 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 Securities and Exchange Commission or other regulatory authorities, which would require additional financial and management resources.

Risks Relating to this Offering

Our sponsors will have significant control over our management and policies, and conflicts of interest may arise because some of our directors are principals of our sponsors.

        Assuming an initial public offering price per share of $            , the midpoint of the range set forth on the cover page of this prospectus, 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 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, following the completion of this offering, the initial authorized number of directors on our board shall be ten, including up to five persons designated by JPMP and up to two persons designated by CPPIB. JPMP will have the right to designate up to six persons in total to serve on our board of directors after an additional two independent directors are added to our board of directors so long as

31



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 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. We operate in a capital intensive industry and an inactive market may also impair our ability to raise capital by selling shares of common stock and may impair our ability to acquire financing needed to implement our windpark development plans.

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, finance and construct planned windparks on time and on budget, including any delays in the conversion of our construction loans into term loans;

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

    changes or proposed changes in, or differing interpretations of, laws or regulations affecting our business, including state renewable portfolio standard programs and the production tax credit;

32


    natural disasters, war and/or terrorism, which may harm the electric transmission network and disrupt our windpark operations;

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

    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. Until the net proceeds are used, we will invest them in investment grade, short-term interest bearing marketable securities. 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.

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

        After this offering, we will have             shares of common stock outstanding. The 23,437,500 shares sold in this offering (or 26,953,125 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. Substantially all of 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.

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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 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 any options to purchase our common stock that we grant under our 2008 Incentive Award Plan 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 sponsors to designate a majority of our board of directors;

    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 1,000,000 shares of preferred stock, par value $0.01 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;

    market or business conditions and fluctuations in demand for and price of energy, capacity or renewable energy certificates 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.

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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 185.


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 the initial public offering price per share in this offering. Our corporate reorganization will be effective prior to the completion of this offering.

        Assuming an initial public offering price per share of $        , the midpoint of the range set forth on the cover of this prospectus, 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 23,437,500 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 windpark 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.

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CAPITALIZATION

        The following table sets forth our consolidated capitalization as of June 30, 2008:

    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 1,000,000 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 23,437,500 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 June 30, 2008
 
  Actual
  Pro Forma
  Pro Forma
As Adjusted(1)

 
  (in thousands)

Total debt(2)   $ 1,241,343   $     $  
Members'/stockholders' equity:                  
  Preferred units, 5,024,761 issued and outstanding, actual; no preferred units issued and outstanding, pro forma and pro forma as adjusted     502,476            
  Common units, 491,056 issued and outstanding, actual; no common units issued and outstanding, pro forma and pro forma as adjusted     49            
  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     (225,984 )          
  Accumulated other comprehensive loss     (6,970 )          
   
 
 
    Total members'/stockholders' equity     269,571            
   
 
 
    Total capitalization   $ 1,510,914   $     $  
   
 
 

(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 set forth on the cover page of this prospectus, remains the same, and after deducting underwriting

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    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.

(2)
Includes $27.7 million of debt related to assets held for sale.

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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 June 30, 2008, was $         million, or $          per share, based on the number of shares of common stock outstanding as of June 30, 2008 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, the midpoint of the range on the cover of this prospectus, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma as adjusted net tangible book value as of June 30, 2008 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 June 30, 2008   $        
  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

41



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 June 30, 2008, 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   23,437,500     % $       % $  
   
 
 
 
 
  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 June 30, 2008 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 26,953,125 shares or            % of the total number of shares of common stock to be outstanding after this offering.

        As of June 30, 2008, there were no options or warrants to purchase common stock outstanding. Effective upon the closing of this offering, an aggregate of 6,800,000 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 summary consolidated financial data as of and for the six months ended June 30, 2008 and 2007 from our unaudited condensed consolidated financial statements included elsewhere in this prospectus. We have derived the selected consolidated financial data as of and for the years ended December 31, 2007, 2006 and 2005 from our audited consolidated financial statements included elsewhere in this prospectus. We have derived the selected consolidated financial data as of and for the period ended December 31, 2004 from our unaudited consolidated financial statements that are not included in this prospectus.

        Pro forma net income (loss) per share is based on the weighted average common units outstanding. Pro forma net income (loss) per share is computed as if the conversion into a Delaware corporation occurred at the beginning of 2007 and we had been taxed as a C corporation.

        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.

 
  Six Months Ended
June 30,

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

 
 
  2008
  2007
  2007
  2006
  2005
 
 
  (in thousands, except for unit and per unit amounts)
 
Revenues:                                      
  Revenues   $ 3,904   $   $   $   $   $  
  Risk management activities related to operating projects     (33,378 )                    
   
 
 
 
 
 
 
Total revenues     (29,474 )                    

Cost of revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Windpark operating expenses     1,002                      
  Depreciation and amortization     4,145                      
   
 
 
 
 
 
 
Total cost of revenues     5,147                      
   
 
 
 
 
 
 
Gross profit (loss)     (34,621 )                    

Expenditures:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  New project development     1,615     1,763     3,625     2,241     10      
    Salaries, wages, employment taxes and fringe benefits     8,166     4,695     10,627     9,788     2,919     352  
    Other general and administrative expenses     7,546     2,904     8,265     4,024     4,771     733  
   
 
 
 
 
 
 
  General and administrative expenses     15,712     7,599     18,892     13,812     7,690     1,085  
  Depreciation     675     339     776     492     83      
  Write-down of assets held for sale and construction in progress     14,910     391     574     5,500          
  Other (income) expense         (15 )   32     18          
   
 
 
 
 
 
 
Total expenditures     32,912     10,077     23,899     22,063     7,783     1,085  
   
 
 
 
 
 
 
Loss from operations     (67,533 )   (10,077 )   (23,899 )   (22,063 )   (7,783 )   (1,085 )
  Risk management activities related to non-operating projects     (85,773 )   888     (21,073 )            
  Other income (expense)     146                      
  Interest expense     (2,568 )                    
  Interest income     1,753     694     2,486     1,384     24      
  Provision for income taxes                          
   
 
 
 
 
 
 
Net loss   $ (153,975 ) $ (8,495 ) $ (42,486 ) $ (20,679 ) $ (7,759 ) $ (1,085 )
   
 
 
 
 
 
 

43


Net loss allocable to common unitholders:                                      
  Net loss   $ (153,975 )   (8,495 )   (42,486 )   (20,679 )            
  Preferred dividend(1)     16,408     8,053     18,662     4,017              
   
 
 
 
             
  Net loss allocable to common unitholders   $ (170,383 ) $ (16,548 ) $ (61,148 ) $ (24,696 )            
   
 
 
 
             
Net loss allocable to common unitholders per unit:                                      
  Basic and diluted   $ (353.03 ) $ (35.72 ) $ (131.99 ) $ (69.49 )            
   
 
 
 
             
  Weighted average units used in the calculation of net loss per unit allocable to common unitholders basic and diluted     482,627     463,260     463,260     355,378              
   
 
 
 
             
Pro forma net loss data (unaudited):                                      
  Net loss allocable to common unitholders as reported   $ (170,383 ) $ (16,548 ) $ (61,148 )                  
  Pro forma adjustment for income tax benefit     N/A                            
   
 
 
                   
  Pro forma net loss allocable to common unitholders   $ (170,383 ) $ (16,548 ) $ (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   $ 27,352   $ (11,267 ) $ 39,921   $ (20,210 ) $ (6,036 ) $ (1,003 )
  Cash flows used by investing activities     (567,247 )   (164,490 )   (617,867 )   (507,141 )   (47,206 )    
  Cash flows provided by financing activities     517,651     206,711     618,043     532,591     54,375     1,359  

(1)
The preferred dividend was not declared (or paid) during the period from August 31, 2004 (date of inception) to June 30, 2008.
 
  June 30,
  December 31,
 
  2008
  2007
  2006
  2005
  2004
 
  (in thousands)

Balance sheet data (at period end):                              
  Cash and cash equivalents   $ 24,582   $ 46,826   $ 6,729   $ 1,489   $ 356
  Restricted cash—current     243,801     50,401     12,995        
  Accounts receivable     2,873                
  Prepaid and other current assets     2,682     9,010     1,925        
  Assets held for sale     92,114     54,497            
  Property and equipment, net     623,685     4,653     3,105     1,409    
  Construction in progress     752,460     959,202     442,435     13,387    
  Restricted cash—long term     18,608                
  Construction material deposits     176,486     150,259     153,493     36,660    
  Deferred financing costs     11,190     15,087     2,251        
  Derivatives     5,207                
  Other assets     3,176     1,208     559     250    
   
 
 
 
 
  Total assets   $ 1,956,864   $ 1,291,143   $ 623,492   $ 53,195   $ 356
   
 
 
 
 
 
Short-term liabilities

 

$

360,413

 

$

135,099

 

$

478,755

 

$

46,619

 

$

82
  Long-term obligations     1,326,880     931,268            
   
 
 
 
 
  Total liabilities     1,687,293     1,066,367     478,755     46,619     82
   
 
 
 
 
 
Members' equity

 

 

269,571

 

 

224,776

 

 

144,737

 

 

6,576

 

 

274
   
 
 
 
 
  Total liabilities and equity   $ 1,956,864   $ 1,291,143   $ 623,492   $ 53,195   $ 356
   
 
 
 
 

44



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 an independent 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 renewable portfolio standard programs and active renewable energy certificate markets.

        We were founded in August 2004 and, while we did not generate revenue until May 2008, our business expanded in many ways during the intervening period. In particular, we grew our land rights from zero to over 400,000 acres, acquired a number of development and construction permits, transmission queue positions and meteorological data as well as contracted to purchase 1,164 turbines from GE. Our development progress facilitated the construction and operation of our three operating windparks, which we refer to as the Initial New York Windparks, and will facilitate the construction and operation of windparks expected to come online during the remainder of 2008 and in future years.

        During the four years since our founding, we have grown our windpark portfolio capacity to 282 MW in operation, 465 MW in construction and 3,104 MW in development, for an aggregate of 3,851 MW. We expect that our current portfolio of windparks in construction and development will be brought into operation by 2012. We also plan to continue to grow our pipeline over the next several years at a rate which maintains or increases the size of our development portfolio.

        We anticipate continuing to take advantage of opportunities to acquire additional land rights in areas with good wind resources, transmission interconnection and an acceptable permitting environment. Additional opportunities may arise from smaller developers who may seek to sell partially developed windparks.

        The primary challenges we face include our limited operating history, our dependence on a limited number of operating windparks, increasing costs in all areas of our business, tighter terms and conditions on debt and tax equity financing made available to us, the amount of capital we need to raise to consummate our business plan, the uncertainty created by recent failed efforts to extend the production tax credit and the vulnerability of our windparks to meteorological and atmospheric conditions.

Recent Developments

        On July 14, 2008, we sold a 25% membership interest in our project company that is developing our expected 99 MW Granite Reliable Windpark located in Coos County, New Hampshire to Freshet Wind Energy LLC. An affiliate of Freshet Wind Energy currently owns a majority of the land required for the siting of the wind turbines at this windpark. In exchange for its membership interest, Freshet

45



Wind Energy paid us approximately $1.8 million in cash, and agreed to pay us an additional $1.6 million in cash upon the earlier to occur of the receipt of project financing for the windpark or the commencement of construction of the windpark. In addition, Freshet Wind Energy has agreed to pay 25% of future development and pre-financing construction costs and turbine purchases.

        On July 3, 2008, we entered into an interest rate swap contract to protect against the impact of changes in the benchmark LIBOR interest rate on the variability of the specified future three month LIBOR semi-annual interest payments relating to our construction and subsequent fifteen year term loan under our financing agreement relating to our Altona, Chateaugay and Wethersfield windparks. This instrument has a notional amount of $211.6 million and we are required to pay a fixed rate of 4.56% and will receive the floating three month LIBOR rate. This contract has been designated as a cash flow hedge.

        On July 3, 2008, we entered into a turbine supply agreement with GE, pursuant to which GE has agreed to supply us with 333 1.5 MW turbines that we will need to support our windparks slated for construction in 2010.

        On June 30, 2008, we entered into a financing agreement with a group of lenders, which provided construction loans of up to $631.8 million and up to $109 million in collateral loans and letters of credit to fund the construction of our Altona, Chateaugay and Wethersfield windparks located in New York. For additional discussion of the financing agreement see "Description of Certain Financing Arrangements—2008 New York Project Financing."

        On June 30, 2008, we entered into a ten-year energy hedging arrangement with Citigroup Energy Inc. relating to the energy that we expect to generate at our Altona, Chateaugay and Wethersfield windparks.

        On May 29, 2008, we executed a termsheet with Novus Windpower LLC and Novus Management LLC that provides us with rights to develop up to 2,500 MW of windparks in the Oklahoma/Texas panhandle region. Our development rights are subject to the requirement that we execute definitive documents on or before October 31, 2008. A portion of these projects have been included in our projects in development for 2011 and 2012, which are discussed elsewhere in this prospectus.

        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, which 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. On June 16, 2008 the prospective purchaser informed us they wish to terminate the agreement. On August 25, 2008, certain of our subsidiaries entered into an agreement with John Deere Renewables, LLC and its wholly owned subsidiary for the sale of the same Huron and Sanilac County assets and wind turbines. Under this agreement, we have agreed to guarantee the obligations of our subsidiaries that are party to the agreement. Pursuant to the agreement, the assets are being transferred to the purchasers in two steps:

    The first step occurred on the date of the agreement and involved the transfer to the purchasers of most of the assets related to the Huron County project as well as all of the membership interests in our subsidiary that holds assets related to the Sanilac County project. The purchasers

46


      paid $91.7 million in exchange for the assets and the membership interests, a portion of which was used to pay off debt that was secured by the assets that we sold.

    After the closing of the first step, we and our subsidiaries continue to hold a FERC-jurisdictional market-based rate tariff and two agreements under that tariff for the sale of power generated by the projects, which cannot be transferred until we obtain FERC approval and certain permits related to the Huron County project, which permits require the approval of Michigan state or local authorities. We expect that these approvals will be received prior to November 15, 2008. Following receipt of these approvals, the purchasers will acquire all of the membership interests in our subsidiary that holds the assets related to the Huron County project for which they will pay an additional $4.5 million, subject to certain adjustments. In addition, the purchasers will pay us $1.0 million upon the earlier of the time at which the purchasers could obtain title insurance with respect to certain real estate parcels related to the Sanilac County project or the sale by the purchasers of at least 50% of the real estate or 50% of the membership interests in Noble Thumb Sanilac Windpark, LLC. If approval of FERC or the Michigan authorities is not received by November 15, 2008 or certain other conditions are not satisfied, then the sale may be unwound, which would require us to repay the purchase price and for the purchasers to return the assets and membership interests. The purchasers also have agreed to manage development of the Huron County projects until the sale is completed.

Revenues

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

    Sale of energy.  We sell the energy that we produce at the Initial New York Windparks into the New York Independent System Operator energy market at the market clearing price on an hourly basis. The market clearing price is determined by supply and demand in the New York Independent System Operator energy 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. Revenues from the sale of energy are impacted by various non-cash items relating to changes in the fair value of our various energy derivative contracts. Over time, these impacts could result in increases or decreases to our revenues. For further discussion, see notes 5 and 8 to our unaudited condensed consolidated financial statements as of and for the six months ended June 30, 2008.

    Sale of renewable energy certificates.  We have agreed to sell the majority of the renewable energy certificates we expect to generate at our Initial New York Windparks to New York State Energy Research and Development Authority, or NYSERDA, the entity that administers the central procurement of renewable energy certificates for the State of New York, pursuant to executed standard form long-term, fixed-price contracts. One renewable energy certificate is created for each MWh of energy we produce. However, the total amount of renewable energy certificates 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 renewable energy certificates that exceed that number in any contract year, we intend to sell the excess renewable energy certificates on the open market.

    Sale of capacity.  We receive monthly payments for the installed capacity at our Initial New York Windparks. These payments are determined by a formula based on a fixed percentage of the installed capacity of the Initial New York Windparks multiplied by a fluctuating price, referred to as the installed capacity price. We have not yet entered into any agreements for the sale of the installed capacity, however, we currently sell the installed capacity directly to the New York Independent System Operator energy market and may also sell to third-party market participants. Prices for the sale of the installed capacity are made at auction clearing prices when

47


      sold through the New York Independent System Operator energy market, or at negotiated market prices at the time of any sale if sold to third-party market participants.

        In order to limit our exposure to price volatility in the New York Independent System Operator energy market, our subsidiary, Noble Environmental Power 2006 Hold Co, LLC, which we refer to as NEP NY 2006, entered into a ten-year energy hedging arrangement with Credit Suisse. Under this financial fixed-for-floating 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 New York Independent System Operator energy market 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 New York Independent System Operator energy market 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 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.

        On June 30, 2008, our subsidiary, Noble Environmental Power 2008 Hold Co., LLC, entered into a ten-year energy hedging arrangement with Citigroup Energy Inc., or Citigroup, in order to limit exposure to price volatility in the New York Independent System Operator energy market for power we expect to produce at our Altona, Chateaugay and Wethersfield windparks. Under this financial fixed-for-floating energy swap arrangement:

    we will pay Citigroup 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

    Citigroup will pay 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.

        As part of this agreement, we will implement a tracking account that tracks, on a monthly basis, the difference between the energy production from our Altona, Chateaugay and Wethersfield windparks and a predetermined notional volume under the swap for that month. Our monthly net settlement payments with Citigroup 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 the risk associated with the inherent volatility associated with the volume of energy production

48


from a windpark. The tracking account will be 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 Citigroup over a five-year period following the end of the hedging arrangement, subject to certain conditions, including the requirement that we make minimum periodic repayments based on our cash flows.

        We anticipate that in future projects we will generate revenue in a similar fashion, including from the sale of energy and renewable energy certificates 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 hedging arrangements with Credit Suisse and Citigroup.

Expenses

        Our principal expenses include those associated with our cost of revenues and operating expenses.

        Cost of revenues. Cost of revenues include windpark depreciation, wind technician labor costs, easement payments to our landowners, insurance, 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 engineering and other professional services.

        Operating expenses. Operating expenses include new project development expenses, general and administrative expenses and certain depreciation expenses. 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."

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

        Depreciation classified in operating expenses includes all depreciable assets with the exception of windpark assets.

Trends and Uncertainties

        Revenues will be a function of the volume of our energy production and the market price of the products related to this energy production, namely renewable energy certificates and capacity. As we have only recently commenced operations of our windparks, we have not been able to determine any significant trends in our energy production, either in absolute terms or relative to our long-term projections of wind energy production. The market price of energy will be reflected in both our short-term sales of unhedged energy and the determination of our long-term hedge price for energy. We have observed an upward trend in the price of energy in the markets in which we operate based, in part, on the rising costs of fossil fuels. We have not observed any clear trend in the market price for renewable energy certificates or capacity in the markets in which we operate as a result of the limited history and liquidity in these markets.

        During the six months ended June 30, 2008, forward-looking power prices increased, which impacted our revenues and net losses by non-cash charges relating to changes in the fair value of our various energy derivative contracts. In future periods, we will face uncertainty with respect to increases or decreases in forward-looking power prices, which could result in non-cash increases or decreases to

49



our revenues and operating income (loss) as a result of our treatment of the fair value of our various energy derivative contracts.

        During recent periods, we have seen increases in the costs relating to key aspects of our windpark development, financing, construction and operations activities that would have a material negative impact on earnings. These include increases in:

    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;

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

        We also face some uncertainty with respect to the extension of the production tax credit, which is scheduled to expire on December 31, 2008. If the production tax credit is not extended or renewed we may be unable to use tax equity financing structures, which may increase our financing costs.

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 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.

        We were formed on August 31, 2004 and were in the development stage through May 13, 2008. The six-month period ended June 30, 2008 is the first period during which we are considered an operating company and are no longer in the development stage.

        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

50



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 renewable energy certificates;

    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 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 June 30, 2008, we had capitalized $168.7 million of these expenses and costs.

        Once a project is placed into operation, all accumulated costs will be reclassified from construction in progress 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 assets whenever events or changes in circumstances indicate the carrying value of our assets may not be recoverable.

        We have written down certain construction in progress, including construction in progress and assets held for sale. Write-offs totaled $14.9 million for the six months ended June 30, 2008, $0.6 million for the year ended December 31, 2007 and $5.5 million for the year ended December 31, 2006. During the six months ended June 30, 2008, we wrote down the carrying cost value of our Noble Thumb Windpark I project in Michigan by $15.2 million in anticipation that net sale proceeds from the then-anticipated sale of the project to John Deere Renewables would be lower than the project's carrying cost. See "—Recent Developments." This was partially offset by the recovery of $0.3 million as a result of a financial settlement between us and the party from which we acquired the development assets of the Noble Berkshire Windpark. For the six months ended June 30, 2007, we had previously written off $0.4 million of costs related to the development of this windpark. The $0.6 million write-off for the year ended December 31, 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 the project development rights to the Noble Berkshire Windpark. 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 totaling $5.5 million related to previously capitalized costs incurred in connection with the development of our Noble Thumb Windpark I. Such costs consisted

51



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, we are seeking to sell the assets associated with this project.

        Accounting for Tax Equity Financing.    On May 13, 2008, we completed a $220 million tax equity financing in connection with refinancing the construction and equity bridge loans for our Initial New York Windparks into a term loan and the sale of an interest in NEP NY 2006, the project holding company that indirectly owns all of the assets of our Initial New York Windparks. We similarly expect to use tax equity financing structures for future windparks. In these structures, the sale of a membership interest in the project holding company or project company represents the sale of an equity interest in an entity that is considered in substance real estate, and, as a result, will be accounted for under the financing provisions of Statement of Financial Accounting Standards, or SFAS, No. 66, "Accounting for Sales of Real Estate." Under this financing method, the interest sold to the tax equity investor is reflected as a financing obligation on our balance sheet, and we retain the windpark assets and any related debt on our balance sheet and continue to report all of the results of the operations of the windparks. The presentation in our income statement reflects revenues and expenses from the windparks' operations on a "gross" basis. Any cash contributed to a project by the tax equity investor will be recorded as an increase to the financing obligation. Using the effective interest method, the financing obligation will be increased each period to reflect the tax equity investor's target rate of return, which will be recorded as interest expense. The financing obligation will be reduced by cash distributions, the allocation of production tax credits to the tax equity investor and the federal income tax impact to the tax equity investor of the allocation of taxable losses, which will be recorded as an adjustment to interest expense. The financing obligation will be increased by the federal income tax impact to the tax equity investor of the allocation of taxable income, which will also be recorded as an adjustment to interest expense. This treatment is expected to remain consistent over the term of a project.

        The federal income tax impact of the difference between straight line book depreciation and the accelerated depreciation used for tax purposes is accounted for as a long-term deferred liability owed to the tax equity investor with an offsetting adjustment to interest expense. The adjustment normalizes the impact on interest expense of the accelerated depreciation used for tax purposes.

        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 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

52



effectiveness testing in accordance with SFAS 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 results of 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.

        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. If forecasted interest payments are no longer expected to occur, any amounts included in comprehensive income related to these payments will be recognized directly in earnings.

        As of June 30, 2008 and December 31, 2007, $3.1 million and $0.7 million, respectively, of deferred losses on derivative instruments related to interest rate cash flow hedges accumulated on our consolidated balance sheet in accumulated other comprehensive income are expected to be recognized in earnings during the next twelve months as the hedged transactions occur. However, due to the volatility of interest rates, the corresponding value in accumulated other comprehensive income for open hedges will likely change prior to its reclassification into earnings.

        The fair value of derivative instruments is determined based upon market quotes from independent sources, when available. When independent quotes are not available, fair value is determined using valuation models. These valuation models require market-driven inputs, including contractual terms, credit spreads and assumptions about the future price of energy, As described below, certain valuation models also require inputs that are not readily observable in the market.

        The fair value of all our derivative contracts at June 30, 2008 and December 31, 2007 was ($137.3) million and ($28.9) million, respectively. This increase in net liability value relates primarily to the increase in energy prices during 2008. We recorded $33.2 million of the decrease in the fair value of our energy swap contracts as a reduction of revenues and $85.2 million as a charge to non-operating expense. In the six months ended June 30, 2008, the market price of electricity rose, which caused the fair value of our energy hedge contracts to decline. We expect to designate a portion of our energy hedge derivative contracts as cash flow hedges. The change in the value of our interest rate swaps has been recorded in other comprehensive income as it has been designated as a hedge under SFAS 133. Prior to exiting the development stage, all changes in the fair value of our energy swap contracts were recorded as an expense.

        We use proprietary models to value our derivative contracts. The selection of a model to value our derivative depends on the contractual terms of, and specific risks inherent in, the instrument as well as the availability of pricing information in the market. For derivatives that are less complex and trade in liquid markets, such as interest rate swaps, we utilize quoted prices on commonly quoted intervals which are interpolated for periods different than the quoted intervals as inputs to a market valuation model. For derivatives that trade in less liquid markets, such as energy hedges, a proprietary model is used because such instruments tend to be unique, contain complex or heavily modified and negotiated

53



terms, and pricing information is not readily available in the market. The more significant assumptions used in the valuation of our energy hedge include assumptions about the future price of energy in New York, and assumptions about future interest rates. It is possible that changes in our assumptions could have an impact on our financial condition or results of operations. These models and the related assumptions are continuously re-evaluated by management and enhanced, as appropriate, based on improvements in modeling techniques.

        Accounting for Income Taxes.    We utilize the asset and liability method of accounting for deferred income taxes as prescribed by SFAS No. 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. As of June 30, 2008, we had recorded a valuation allowance against our net deferred tax assets as realization of these deferred tax assets is uncertain. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences and carryforwards become deductible or utilized. As of June 30, 2008, based upon the level of historical taxable losses, a valuation allowance of approximately $54.7 million was recorded in accordance with the provisions of SFAS No. 109, Accounting for Income Taxes. In June 2006, the Financial Accounting Standards Board, or the FASB, issued Interpretation No. 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. At June 30, 2008 and December 31, 2007, the Company had asset retirement obligations of $4.2 million and $4.0 million, respectively.

Recent Accounting Pronouncements

        In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally Accepted Accounting Principles." SFAS 162 defines the order in which accounting principles that are generally accepted should be followed. SFAS 162 is effective 60 days following the Securities and Exchange Commission's approval of the Public Company Accounting Oversight Board amendments to AU Section 411, "The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles." We do not expect the adoption of SFAS 162 to have a material impact on our consolidated financial statements.

        In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities," which expands derivative disclosure by requiring an entity to disclose: (i) an

54


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 No. 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 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

55



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 June 30, 2008, including the fair value measurements and the levels of inputs used in determining those fair values as we would expect to report them had we adopted SFAS 157 as of June 30, 2008.

Description

  Total at
June 30,
2008

  Quoted Market
Prices for Identical
Assets (Level 1)

  Significant Other
Observable Inputs
(Level 2)

  Significant
Unobservable
Inputs
(Level 3)

 
  (in thousands)
Assets:                      
Derivative Contracts:                      
  Interest rate swaps(1)   $ 5,207     $ 5,207    

Liabilities:

 

 

 

 

 

 

 

 

 

 

 
Derivative Contracts:                      
  Energy hedge contracts(2)   $ 139,414         $ $139,414
  Interest rate swaps(1)   $ 3,098     $ 3,098    

(1)
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.

(2)
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.

Results of Operations

Operating Statistics

        We commenced commercial power generation on May 13, 2008. During the six months ended June 30, 2008 we generated 59,265 MWh of commercially saleable electricity with a 93.9% turbine availability. Our turbine availability is a measurement of the percentage of time that the wind turbines are ready to generate power (that is, they are not out of service for maintenance or repair).

56


Comparison of the Six Months Ended June 30, 2008 and June 30, 2007

 
  Six Months Ended June 30,
   
 
 
  Period-to-
Period
Change

 
 
  2008
  2007
 
 
  (in thousands)

 
Revenues:                  
  Revenues   $ 3,904   $      
  Risk management activities related to operating projects     (33,378 )        
   
 
     
Total revenues     (29,474 )     NM  
Cost of revenues:                  
  Windpark operating expenses     1,002          
  Depreciation and amortization     4,145          
   
 
     
Total cost of revenues     5,147       NM  
   
 
     
Gross profit (loss)     (34,621 )     NM  
   
 
     
  New project development     1,615     1,763   -8.4 %
  General and administrative expenses     15,712     7,599   106.7 %
  Depreciation     675     339   99.3 %
  Write-down of assets held for sale and construction in progress     14,910     391   3,713.3 %
  Other income         15   NM  
   
 
     
Total expenditures     32,912     10,077   226.6 %
   
 
     
Loss from operations     (67,533 )   (10,077 ) 570.2 %
   
 
     
  Risk management activities related to non-operating projects     (85,773 )   888   NM  
  Other income     146       NM  
  Interest (expense) income, net     (815 )   694   NM  
   
 
     
Net loss   $ (153,975 ) $ (8,495 ) 1,712.5 %
   
 
     

      *
      NM = not meaningful

        Revenues.    We began generating revenues in the second quarter of 2008 when our Initial New York Windparks commenced commercial operations. Revenues generated from windparks were $3.9 million for the six months ended June 30, 2008. We entered into a ten-year fixed-for-floating energy hedging arrangement with Credit Suisse in June 2007. The change in the fair value of this derivative contract associated with the wind generating assets that occurred subsequent to these windparks becoming operational on May 13, 2008 was $33.2 million and was recorded as a net liability increase with a corresponding reduction to revenues.

        Cost of revenues.    Cost of revenues for the six months ended June 30, 2008 was $5.1 million. As discussed above, we began generating revenues in May 2008 and, accordingly, there is no comparable cost of revenues for the six months ended June 30, 2007. Cost of revenues is comprised of $1.0 million of windpark operating expenses and $4.1 million of windpark depreciation expense associated with the windparks. Windpark operating expenses consist primarily of easement payments, insurance costs and maintenance operations, parts and service and windpark technician salaries and wages.

        New Project Development Expenses.    New project development expenses for the six months ended June 30, 2008 were $1.6 million, as compared with $1.8 million for the six months ended June 30, 2007, which represented a decrease of $0.2 million, or 8.4%. The decrease was primarily the result of reduced easement, permitting, legal, tools and rental expenditures partially offset by increased interconnection development and development management costs.

57


        General and Administrative Expenses.    General and administrative expenses for the six months ended June 30, 2008 were $15.7 million, as compared with $7.6 million for the six months ended June 30, 2007, which represented a $8.1 million or 106.7% increase. This increase was due primarily to increases in salaries, wages, employment taxes and fringe benefits of $3.5 million from $4.7 million for the six months ended June 30, 2007 to $8.2 million for the six months ended June 30, 2008, as well as increases in: (i) professional fees (legal and accounting services) of approximately $2.4 million; (ii) other professional fees of $0.7 million; and (iii) travel, recruiting fees, utilities, bank service charges, dues and subscriptions, management information services and other overhead expenses of $1.5 million. Increased salaries, wages, employment taxes and fringe benefits was due to an overall increase in headcount across our business to 176 persons at June 30, 2008 from 97 persons at June 30, 2007. In addition, we hired several executives during this timeframe which further increased salary and wage expense from that of prior periods. 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 (non-windpark) for the six months ended June 30, 2008 was $0.7 million, as compared to $0.3 million for the six months ended June 30, 2007, which represented a $0.4 million or 99.3% increase. The increase was due to additions to property and equipment of $2.8 million during the last 12 months.

        Write-off of Construction in Progress.    During the six months ended June 30, 2008, we wrote down the carrying cost value of our Noble Thumb Windpark I project by $15.2 million in anticipation that sales proceeds less selling costs from the then-anticipated sale of the project to John Deere Renewables would be lower than the project's carrying cost. See "—Recent Developments." This was partially offset by our recovery of $0.3 million as a result of a financial settlement between us and the party from which we acquired the development assets of the Noble Berkshire Windpark. During the six months ended June 30, 2007, we had written off $0.4 million of costs related to the development of the this windpark as it was decided to no longer pursue the project.

        Risk Management Activities Related to Non-Operating Projects.    We entered into a ten-year fixed-for-floating energy hedging arrangement with Credit Suisse in June 2007. In addition, we entered into a ten-year fixed-for-floating energy hedging arrangement with Citigroup on June 30, 2008. The decrease in the fair value of these derivative contracts associated with the wind generating assets that were not yet generating commercially salable power during the six month period ended June 30, 2008 was $85.2 million. This amount includes a $52.1 million inception loss in connection with the Citigroup derivative contract entered into on June 30, 2008. The loss resulted from the quoted forward unit power prices used by our model to value the derivative at its inception exceeding the fixed unit price of the derivative contract. As the wind generating assets associated with these instruments did not generate power for all of the six months ended June 30, 2008, and these instruments were not designated as cash flow hedges in accordance with SFAS 133, we recorded the decrease in the fair value as a liability and expense for the periods that the underlying assets were not in commercial production. In the six months ended June 30, 2008, as a result of the increased forward market price of electricity, the liability value of our contracts with Credit Suisse and Citigroup increased.

        Other Income.    Other income was $0.1 million for the six months ended June 30, 2008. The increase of $0.1 million resulted from the recovery of a note that had been written off in the fourth quarter of 2007.

        Interest (Expense) Income, Net.    Net interest expense for the six months ended June 30, 2008 was $0.8 million, as compared with $0.7 million of interest income for the six months ended June 30, 2007, which represented a $1.5 million increase. The increase was principally driven by an increase in interest expense of $2.6 million partially offset by an increase in interest income of $1.1 million. Increased interest expense was primarily the result of no longer capitalizing the interest costs associated with

58



financing our Initial New York Windparks during the construction phase. Increased interest income was due to increased invested cash balances as a result of increased restricted cash and increased excess cash availability during the six months ended June 30, 2008 compared with the six months ended June 30, 2007.

        Net Loss.    Net loss for the six months ended June 30, 2008 was $154.0 million, as compared with $8.5 million for the six months ended June 30, 2007, which represented a $145.6 million increase. This increase was attributable to the following factors: (i) an increase in the combined changes in fair value of derivative contracts of $120.0 million relating to the decrease in the fair value of our energy hedging arrangements with Credit Suisse and Citigroup; (ii) an increase in general and administrative costs of $8.1 million relating to salaries, wages, employment related taxes and fringe benefits of $3.5 million due to increased headcount, increased professional fees of approximately $3.1 million and an increase in travel, utilities, bank service charges, dues and subscriptions, management information services and other overhead expenses of approximately $1.5 million; (iii) an increase in net interest expense of $1.5 million related to the commencement of operations of our Initial New York Windparks partially offset by increased interest income due to increased invested cash balances; (iv) an increase in depreciation of $4.5 million primarily as a result of wind generating assets becoming operational; (v) windpark operating expenses of $0.9 million; and (vi) a $14.5 million increase in write-down of assets held for sale and construction in progress.

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 %
   
 
     
Total expenses     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.

        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 I Windpark. 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.

59


        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-floating 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 expense.

        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, respectively, 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 following factors: (i) an increase in salaries, wages and employment taxes of $0.8 million due to increased headcount; (ii) an increase in general and administrative expenses of $4.3 million relating to increases in professional fees 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; (iii) an increase in depreciation expense of $0.5 million due to additions to property and equipment of $2.6 million during 2007; (iv) an increase in new project development expenses of $1.4 million associated with the expansion of our development activities; and (v) an increase in change in fair value of derivative contract of $21.0 million relating to the decrease in the fair value of our energy hedging arrangement with Credit Suisse. These increases totaling $28.0 million were partially offset by a decrease in write-off of construction in progress of $4.9 million and an increase in interest income of approximately $1.1 million.

60


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        
   
 
     
Total expenses     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.

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        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 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 following factors: (i) an increase in salaries wages and employment taxes of $6.9 million due to increased headcount; (ii) an increase in write-off of construction in progress of $5.5 million associated with previously capitalized costs incurred in the development of Noble Thumb Windpark I; (iii) an increase in depreciation expense of $0.4 million due to additions to property and equipment of $2.4 million during 2006; and (iv) an increase in new project development expenses of $2.2 million associated with the expansion of our development activities. These increases totaling $15 million were partially offset by a decrease in general and administrative expenses of approximately $0.8 million and an increase in interest income of approximately $1.4 million.

Liquidity and Capital Resources

        In addition to funding our general corporate, administrative and 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 in the three year period ending December 31, 2010.

        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, including the proceeds from this offering, together with borrowings under our turbine credit facilities, equity infusion from our sponsors, additional sales of equity, capital contributions from tax equity investors, current and future borrowings under project construction and term loans and expected distributions from our windparks, 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

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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 places 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.

        As discussed above under "—Expenses," we have experienced increasing costs of capital required to fund our business. Additionally, trends in global capital markets may lead to a reduction in the number of capital providers willing to provide funding to us, and this would lead to a reduction in liquidity and our access to capital. These trends may have a negative impact on our results of operations.

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 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 of 6.75% as of June 30, 2008. We are also required to pay a commitment fee, currently equal to 1.375%, on the undrawn portion of the facility. As of June 30, 2008, we had $22.8 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 production tax credits 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.

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        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 June 30, 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 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 facilities that we entered into in connection with the construction of the Initial New York Windparks and our Altona, Chateaugay and Wethersfield windparks, see "Description of Certain Financing Arrangements—Initial

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New York Project Financing" and "—2008 New York Project Financing," respectively. 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. On June 30, 2008, we secured construction loans of up to $631.8 million and up to $109 million in collateral loans and letters of credit for the construction of our Altona, Chateaugay and Wethersfield windparks. At June 30, 2008, we had $347.1 million and $71.9 million outstanding under the construction loan and collateral loans, respectively.

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 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 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.

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        On May 13, 2008, we refinanced 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 was converted into a ten-year term loan facility; and

    the tax-equity investor made an equity investment of approximately $220.0 million in NEP NY 2006, our subsidiary that owns the Initial New York Windparks.

        In addition, the tax equity investor in the Initial New York Windparks has agreed to contribute additional amounts at the end of each fiscal quarter based on the amounts of production tax credits 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 investor in the Initial New York Windparks are governed by the limited liability company agreement of NEP NY 2006. We refer to this operating agreement as the New York 2006 LLC Agreement.

        The New York 2006 LLC Agreement provides that we 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 also governs 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 changes 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, which initially was $6.1 million, is first reduced to zero or (ii) April 30, 2012. We refer to this date 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 May 13, 2018 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 investor reaches 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 production tax credits 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
  Production Tax Credits
and Profits/Losses(1)

 
 
  Noble
  Investor
  Noble
  Investor
 
Year One — Cash Flip   100 % 0 % 0 % 100 %
Cash Flip — Flip Point   0 % 100 % 0 % 100 %
After Flip Point   95 % 5 % 95 % 5 %

      (1)
      Production tax credits provide the tax equity 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.

        In future windparks, production tax credits and profits and losses generally will be allocated for income tax purposes 99% to the tax equity investor and 1% to us over the initial 10-year period to conform to an IRS safe harbor for wind credit investment structures. Additionally, in future windparks we may agree to share the cash distributions with the tax equity investor in ratios different from those

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agreed to in the New York 2006 LLC Agreement. For a discussion of the allocations and distributions that have been agreed to in connection with the tax equity financing of our Altona, Chateaugay and Wethersfield windparks, see "Description of Certain Financing Arrangements—2008 New York Project Financing—Amended and Restated Limited Liability Company Agreement—Allocations and Distributions."

        Tax equity investors are willing to provide us with relatively low-cost capital because they can use the production tax credits 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.

        On May 7, 2008, we terminated our interest rate swap contract dated November 8, 2007 and entered into a new instrument. The new instrument has a notional amount of $229.1 million, and we pay a fixed rate of 4.169% and receive a floating six month LIBOR rate. We paid approximately $9.2 million to settle the November 8, 2007 contract. On May 7, 2008, we also terminated our interest rate swap contract dated February 22, 2008 and entered into a new instrument. The new instrument has a notional amount of $80 million, and we pay a fixed rate of 4.1390% and receive a floating six month LIBOR rate. We paid approximately $0.1 million to settle the February 22, 2008 contract.

Historical Cash Flows

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

 
  Six Months
Ended June 30

  Year Ended December 31,
 
 
  2008
  2007
  2007
  2006
  2005
 
 
  (in thousands)

 
Cash flows provided (used) by operating activities   $ 27,352   $ (11,267 ) $ 39,921   $ (20,210 ) $ (6,036 )
Cash flows used by investing activities     (567,247 )   (164,490 )   (617,867 )   (507,141 )   (47,206 )
Cash flows provided by financing activities     517,651     206,711     618,043     532,591     54,375  

    Cash Flows for the Six Months Ended June 30, 2008

        Net cash provided by operating activities for the six months ended June 30, 2008 was $27.4 million, as compared with net cash used by operating activities of $11.3 million for the six months ended June 30, 2007. The increase in cash provided by operating activities of $38.7 million was principally due to the following factors: (i) a $47.7 million increase in accounts payable and accrued expenses during the six months ended June 30, 2008 as compared to the same period a year ago as a result of increased operating activity; and (ii) a $6.7 million increase in cash generated from reduced prepaid and other current assets principally due to reduced deposits under our contracts with NYSERDA for the sale of renewable energy certificates from the Initial New York Windparks, which were replaced by letters of credit. These increases in cash provided by operations were partially offset by the following: (i) a $145.5 million increase in the net loss in the six months ended June 30, 2008 as compared with the six months ended June 30, 2007; and (ii) a $129.8 increase in non-cash adjustments during the six months ended June 30, 2008 compared with the six months ended June 30, 2007. This increase in non-cash adjustments was principally comprised of a $110.2 million increase in the change in value of derivatives, a $14.8 million increase in write-off of construction in progress and a $4.5 million increase in depreciation.

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        Net cash used by investing activities for the six months ended June 30, 2008 was $567.2 million, as compared with $164.5 million for the six months ended June 30, 2007. The increase in cash used by investing activities of $402.8 million resulted from increased net spending on property and equipment and construction in progress of $156.0 million during the six months ended June 30, 2008 as compared with the same period a year ago. This increase was associated with increased spending on project development, construction and wind turbine and transportation costs as our construction efforts continued to accelerate in 2008 as compared with 2007. In addition, our restricted cash balances, primarily associated with collateral requirements on our outstanding letters of credit, increased by $199.4 million during the six months ended June 30, 2008, as compared to the six months ended June 30, 2007. Furthermore our construction deposit requirements increased by $25.5 million for the six months ended June 30, 2008, as compared with the six months ended June 30, 2007 as a result of increased construction activity during 2008. Finally, assets held for sale increased by $22.0 million for the six months ended June 30, 2008, as compared to June 30, 2007 as result of commencing the sale process for our Noble Thumb I Windpark during the fourth quarter of 2007.

        Net cash provided by financing activities for the six months ended June 30, 2008 was $517.7 million, as compared with $206.7 million for the six months ended June 30, 2007. The increase in cash provided by financing activities of $310.9 million resulted from an increase in proceeds from borrowings of $319.7 million, increased equity purchases of $147.8 million, partially offset by increased repayments of borrowings of $156.4 million. Increased borrowings during the six months ended June 30, 2008 were the result of a $220.0 million tax equity financing that occurred at term conversion of our construction and equity loans for our Initial New York Windparks in May 2008 and increased construction loan and collateral loan borrowings required to support increased construction activity compared with the same time period a year ago. Increased equity purchases were principally the result of $160.0 million of equity investments by CPPIB during the six months ended June 30, 2008 partially offset by decreased investments by other investors. Increased repayments of borrowing resulted from the May 2008 term conversion and the resulting debt repayment of $160.3 million.

    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. During 2007, our construction activities increased significantly. As a result, we experienced an increase in accounts payable and accrued expenses for construction related expenditures as well as an increased accrual during the year ended December 31, 2007 for the final 10% of turbine payments which are due upon the commissioning of the turbines. The increase in non-cash adjustments is principally the result of a $21.1 million change in fair value of derivative contracts partially offset by a $4.9 million decrease in write-offs of construction in progress. The increased change in other current and non-current assets was principally the result of increased deposits related to operating activities.

        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 $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.

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        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 $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 $12.9 million and operating cash use due to changes in assets and liabilities of $7.5 million, offset by the effect of non-cash adjustments to net loss of $6.2 million due mainly to the $5.5 million write-off of construction in progress during 2006. Changes in cash flows related to assets and liabilities were principally the result of reduced growth of non construction in progress related accounts payable and accrued expenses in 2006 as compared to 2005 as our expenditures continued to shift toward construction related activities. Any growth in accounts payable amounts included in construction in progress was netted from the cash flow of each of these categories and therefore did not impact operating cash flows. In addition, $1.5 million of deposits related to transportation activities were outstanding at December 31, 2006 versus none in the preceding year.

        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 $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 June 30, 2008, our debt consisted of:

    $282.8 million of borrowings under our turbine credit facilities (including $27.7 million of debt related to assets held for sale);

    $324.7 million of borrowings under our ten-year term loan facility for the Initial New York Windparks;

    $347.1 million of borrowings under our construction loan for our Altona, Chateaugay and Wethersfield windparks;

    $71.9 million of borrowings under our collateral loan for our Altona, Chateaugay and Wethersfield windparks;

    $214.7 million of borrowings under our tax equity financing for the Initial New York Windparks; and

    $0.2 million of borrowings under capital leases.

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        In addition, at June 30, 2008, we had $158.2 million in letters of credit outstanding. See "—Off-Balance Sheet Arrangements."

Contractual Obligations

        The following table sets forth our material contractual obligations as of December 31, 2007:

 
  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
Fixed interest obligations (interest only)     100,438     39,000     61,438        
Other long-term liabilities                    
   
 
 
 
 
Total   $ 2,056,291   $ 638,841   $ 962,849   $ 64,295   $ 390,306
   
 
 
 
 

        Purchase obligations are comprised of turbine supply agreement commitments, construction commitments and other contractual obligations. Turbine supply agreement commitments are purchase orders between us and the turbine supplier that serve as a master contract for the sale of power wind generation equipment and related services. Construction commitments are subcontract agreements between us and subcontractors for materials and/or services to be performed in the near future.

        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 or Citigroup under our financial energy hedging agreements. See "—Revenues." See note 10 to our consolidated financial statements for further discussion.

        The terms of our easement agreements vary and are complex in nature, but typically establish an evaluation period and an operational period that normally comprises a 20 year term with an option for an additional 30 year extension. Some easements also recognize a separate construction period. Easement payments may be made to the landowner at each stage. Evaluation period payments are generally set at a fixed amount per acre of land, payable quarterly; construction period payments, if applicable, are based on the expected output of the wind turbines that are to be located on the real property; operating period payments are calculated as the greater of a fixed payment or an amount that is contingent on the actual revenues that are generated from the windpark once it goes on-line. Generally, the easements obligate us to make evaluation period payments for a fixed number of years and operations payments for the term of the easement.

        In accordance with SFAS No. 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 June 30, 2008 and 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

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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.

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 many of our other windparks, a decline in energy market prices below 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 renewable energy certificates we anticipate generating from our Initial New York Windparks and our four windparks in New York that are expected to commence operations in 2008 under executed ten-year fixed price contracts, a small portion of the renewable energy certificates we expect these windparks to generate, and all of the renewable energy certificates 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 renewable energy certificates, a decrease in the market price of renewable energy certificates or changes in state and federal regulatory policy may decrease our ability to sell renewable energy certificates in the volumes we forecast or could reduce the sales price of our renewable energy certificates, 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 for our Initial New York Windparks, 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. In future periods, we will face uncertainty with respect to increases or decreases in forward-looking power prices, which could result in non-cash increases or decreases to our revenues and operating income (loss) as a result of our treatment of the fair value of our various energy derivative contracts. Finally, hedging arrangements expose us to risk of financial loss if a counterparty defaults.

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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 entered into in connection with our Altona, Chateaugay and Wethersfield 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 LIBOR interest payments relating to all but $20.0 million of the principal of our term loan facility for our Initial New York Windparks. 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 June 30, 2008, we had $22.8 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 production tax credits 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 production tax credits has not been extended beyond December 31, 2009 (with tax benefits similar to or better than the production tax credits applicable under the current production tax credit), 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

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applicable turbine supply agreements will be in effect for at least 24 months after the expected 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 June 30, 2008, 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 Facilities

RBS 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. On June 9, 2008, the Master Credit Agreement was amended to increase the amount of the facility.

        The maximum amount of letter of credit obligations that may be outstanding at any time under the Master Credit Agreement is $75.0 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 June 30, 2008, there was a face amount of $41.7 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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KeyBank Letter of Credit Facility

        On June 30, 2008, our subsidiary, Noble Credit Funding II, LLC, or Noble Credit II, entered into a letter of credit facility with KeyBank National Association, or KeyBank. Under this revolving letter of credit facility, KeyBank may issue, on behalf of Noble Credit II 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 letter of credit.

        The maximum amount of letter of credit obligations that may be outstanding at any time under the letter of credit is $40.0 million. The letter of credit expires on March 31, 2009. As of June 30, 2008, there was a face amount of $40.0 million outstanding under this letter of credit.

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.

        On May 13, 2008, the construction loan and $19.3 million of the equity bridge loan converted into a term loan. 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 May 13, 2008. Additionally, on May 13, 2008, $160.3 million of the equity bridge loan discussed above was repaid from the proceeds of the initial equity investment by EFS Noble Holdings, LLC, a wholly-owned subsidiary of General Electric Capital Corporation, in NEP NY 2006.

    Interest Rate

        All borrowings under the construction loan and the equity bridge loan accrued 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 May 13, 2008.

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

    (i)
    1.250% from and including May 13, 2008 to but excluding May 13, 2013;

    (ii)
    1.375% from and including May 13, 2013 to but excluding May 13, 2017; and

    (iii)
    1.500% from and including May 13, 2017 to and including the date the term loan matures.

    Distribution Reserve Account

        Amounts that would otherwise be available for distribution to the equity holders of NEP NY 2006 except for the failure to meet the distribution requirements will be held in the distribution reserve

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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 Initial New York 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 24 consecutive months will be used to prepay the loans.

    Prepayments

        NEP NY 2006 may, at its option, prepay the term loan, the debt service reserve account letter of credit loan or the energy hedge letter of credit loan, provided that, after giving effect to any such prepayment, the outstanding obligations under such loans do not exceed $20.0 million in the aggregate. NEP NY 2006 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.

        NEP NY 2006 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

        NEP NY 2006's obligations under the term loan are secured by a first priority lien, subject to certain permitted liens, on the assets of NEP NY 2006 including its interest in the project companies which own the Initial New York Windparks, and a first priority pledge of the equity interests in NEP NY 2006 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 NEP NY 2006's subsidiaries and their assets (including the turbine supply agreements). NEP NY 2006's obligations under the term loan are also secured by a first priority pledge of the equity interests in NEP NY 2006 by EFS Noble Holdings.

    Certain Covenants and Events of Default of Term Loan

        The term loan contains a number of covenants including those that restrict, subject to certain exceptions, NEP NY 2006'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 term loan includes customary affirmative covenants and events of default, including a cross-default for certain other debt of NEP NY 2006 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 2007 ECCA, with EFS Noble Holdings, LLC, an affiliate of GE, which we refer to as EFS. By executing the 2007 ECCA, EFS committed, upon the satisfaction of certain conditions, to make an equity capital contribution in NEP NY 2006, in exchange for Class A membership interests. Those conditions included, among others, the substantial completion of a certain number of wind turbines for the Initial New York Windparks, and satisfaction or waiver of all conditions to borrowing of the term loan under the financing agreement.

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        The conditions set forth in the 2007 ECCA were satisfied (or waived) on May 13, 2008. Accordingly, on such date, (i) EFS made an equity capital contribution in the amount of $220.0 million, (ii) NEP NY 2006 issued Class A membership interests to EFS, (iii) NEP NY 2006 issued Class B membership interests to Noble Prime in exchange for its original membership interest in NEP NY 2006; and (iv) Noble Prime and EFS executed an Amended and Restated Limited Liability Company Agreement governing NEP NY 2006, as described below.

Pay-As-You-Go Capital Contribution Agreement

        In June 2007, Noble Prime and NEP NY 2006 also entered into a Pay-As-You-Go Capital Contribution Agreement, or PAYG agreement, with EFS. Pursuant to the PAYG agreement, at the end of each fiscal quarter after the initial equity capital contribution date, EFS is obligated to make a cash capital contribution to NEP NY 2006 based on the amount of production tax credits generated by the projects during such fiscal quarter.

        EFS' obligation to make such capital contributions terminates on the earliest of: (i) May 13, 2018, (ii) the date that the lenders under the financing agreement take title to the Class A membership interests by exercising remedies under EFS' pledge of such interests, and (iii) the date that EFS realizes its target after-tax rate of return, but only if the term loan is repaid. If the term loan has not been repaid when EFS realizes its target after-tax rate of return, then NEP NY 2006 shall thereafter apply all of EFS' capital contributions to the prepayment of the term loan.

Amended and Restated Limited Liability Company Agreement

        Pursuant to the 2007 ECCA, on May 13, 2008, Noble Prime entered 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 provides for two classes of membership interests, Class A membership interests and Class B membership interests. We currently hold 100% of the outstanding Class B membership interests, and EFS holds 100% of the outstanding Class A membership interests.

    Management

        Under the terms of the New York 2006 LLC Agreement, Noble Prime is the managing member of NEP NY 2006 and is 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 of the projects has been 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 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 are limited to a small subset of these material actions reflecting the Class A members' reduced economic interest. Material actions 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 must 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 is 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 is required to act in accordance with a prudent operator standard.

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In discharging its duties as managing member, Noble Prime is permitted to rely on legal counsel, qualified industry consultants or other advisors. Noble Prime can 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 production tax credits 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 May 13, 2018 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 is a pre-determined after-tax internal rate of return, taking into account cash contributions and distributions as well as the tax benefits (primarily production tax credits 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, which initially was $6.1 million, is first reduced to zero or (ii) April 30, 2012. 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 provides 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 production tax credits) sustained by such person as a result of the breach. In addition, the members made certain covenants to each other, the breach of which 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 production tax credit. Accordingly, to avoid potential related party problems, as managing member, Noble Prime is 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 is obligated to indemnify the members for any damages (including the value of lost production tax credits) 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 is obligated to indemnify NEP NY 2006, the project company and the other members for any damages (including the value of lost production tax credits) suffered as a result.

    Array Loss.  The Class B member has agreed not to develop or construct any windpark, other than our windparks under construction in Chateaugay and Bellmont, within 20 rotor diameters of the Initial New York Windparks if it could reasonably be expected to result in a 0.5% or greater reduction of the net annual energy output of the Initial New York Windparks, unless the

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      Class B member agrees to compensate the affected windpark for any damages. If the reduction could reasonably be expected to be 2.0% or greater, the Class B member is required to obtain the approval of a majority of the Class A members. With respect to our windparks under construction in Chateaugay and Bellmont, the Class B member has entered into a separate affiliate array loss agreement setting forth the terms of compensation payable to the affected windpark.

    Estoppel and New York State Electric and Gas, or NYSEG, Events.  NEP NY 2006 has agreed 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 windpark. NEP NY 2006 similarly has agreed 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 windpark. 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 provides 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 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.

    Transfers

        Under the terms of the New York 2006 LLC Agreement, the members' ability to transfer their interests in NEP NY 2006 is 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 provides 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 apply to the transfer of controlling interests in the members.

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        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 has 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 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 provides that the Class B member has 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 has 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 May 13, 2013. The Class B member also has 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 is 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 results in the redeemed Class A members having realized a pre-determined after-tax internal rate of return.

        All members 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.

2008 New York Project Financing

Construction Loan Facility; Term Loan Facility

        In June 2008, an indirect subsidiary of the company, Noble Environmental Power 2008 Hold Co., LLC, which we refer to as NEP NY 2008, entered into a financing agreement, which we refer to as the 2008 New York financing agreement, with (i) Citibank, N.A., as administrative agent for the lenders and collateral agent for the secured parties, (ii) Citibank Global Markets Inc., acting on behalf of Citibank, N.A., as joint lead arranger and joint bookrunner, (iii) RBS Securities Corporation, doing business as RBS Greenwich Capital, as syndication agent, (iv) HSH Nordbank AG, New York Branch, and The Royal Bank of Scotland plc, as co-documentation agents, (v) RBS Securities Corporation, doing business as RBS Greenwich Capital, and HSH Nordbank AG, New York Branch, as joint lead arrangers and joint bookrunners and (vi) the lenders party thereto, to fund approximately 330 MW of windparks located in western and northern New York, including the construction of (i) the approximately 97.5 MW Noble Altona Windpark in Altona, New York, (ii) the approximately 106.5 MW Noble Chateaugay Windpark in Clinton and Franklin Counties, New York and (iii) the approximately 126 MW Noble Wethersfield Windpark in Wyoming County, New York. The 2008 New York financing agreement provides for construction loans in an amount of up to approximately $631.8 million in the aggregate, with a maturity date of the earliest to occur of March 31, 2009, the date we commence operations of our Altona, Chateaugay and Wethersfield windparks and such earlier date on which all amounts outstanding under the construction loan facility become due in accordance with the 2008 New York financing agreement. In addition, in connection with the construction loan facility, we agreed to make cash equity contributions to NEP NY 2008, to be supported by acceptable letters of credit, to cover cost overruns, completion reserves and the repayment of any portion of the construction loans that are not converted into term loans as described below. The term loans will

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mature, and the letter of credit facility will expire, approximately fifteen years after the date of term conversion. The portion of construction loans not converted into term loans on the date of term conversion will be required to be repaid with equity contributions at such time. As of June 30, 2008, we had $347.1 million outstanding under the construction loan.

Cash Collateral Loans and Letters of Credit

        In addition to the loan facilities described above, as of the effectiveness of the 2008 New York financing agreement, up to $109.0 million is available to NEP NY 2008 in the form of cash collateral loans and/or letters of credit to be issued for the purpose of supporting certain obligations of NEP NY 2008 and its subsidiaries. The issuance of any letters of credit is subject to the agreement of a lender to become an issuing bank on the terms described in the 2008 New York financing agreement. Of this $109.0 million, up to $55.0 million may be issued in support of obligations under NEP NY 2008's energy hedge agreement (which support obligations will fall away shortly after term conversion as described above), up to $30.0 million may be issued in support of obligations under a debt service reserve account required to funded by NEP NY 2008 at the time of term conversion as described above and up to $24.0 million may be issued in support of obligations under other commercial contracts (which $24.0 million will be reduced to $4.0 million on the date that is six months after the date of term conversion as described above). As of June 30, 2008, we had $71.9 million in cash collateral loans outstanding under the 2008 New York financing agreement. Upon satisfaction of the applicable conditions to term conversion, a portion of the construction loans will convert to term loans in an amount of up to $440.0 million.

    Interest Rate

        All borrowings under the construction loan facility will accrue interest at LIBOR plus 1.75% from and including the closing date to but excluding the date of term conversion.

        All borrowings under the term loan facility are expected to accrue interest at LIBOR plus:

    (i)
    1.75% from and including the date of term conversion to but excluding the fourth anniversary thereof;

    (ii)
    1.875% from and including the fourth anniversary of the date of term conversion to but excluding the eighth anniversary thereof; and

    (iii)
    2.00% from and including the eighth anniversary of the date of term conversion to but excluding the tenth anniversary thereof;

    (iv)
    2.25% from and including the tenth anniversary of the date of term conversion to but excluding the twelfth anniversary thereof; and

    (v)
    2.50% from and including the twelfth anniversary of the date of term conversion and thereafter.

    Distribution Reserve Account

        Amounts that would otherwise be available for distribution to the equity holders of NEP NY 2008 will be held in the distribution reserve account until specified 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 Altona, Chateaugay and Wethersfield 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 24 consecutive months will be used to prepay the loans.

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    Prepayments

        NEP NY 2008 will be permitted, at its option, to prepay the loans, the debt service reserve account letters of credit, the energy hedge letters of credit or the project agreement letters of credit.

        NEP NY 2008 will be obligated to make mandatory prepayments of loans:

    (i)
    as described above on the date of term conversion;

    (ii)
    to the extent that a change in law makes it unlawful or impossible for a lender to make or maintain the loans;

    (iii)
    subject to certain conditions set forth in the financing agreement, to the extent that the proceeds of extended term loans have not been applied to the payment of certain project costs relating to incomplete turbines;

    (iv)
    to the extent that the independent engineer determines that a 2% or greater decrease in energy production levels could result from the erection of upwind turbine generators and NEP NY 2008 fails to meet certain required projected debt service coverage ratios; and

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

    Security

        NEP NY 2008's obligations under the credit facilities are secured by a first priority lien, subject to certain permitted liens, on substantially all of the assets of NEP NY 2008 and a first priority pledge of the equity interests in NEP NY 2008 by our wholly-owned subsidiary through which we own NEP NY 2008, Noble Environmental Power 2008 Hold Co. Prime, LLC, which we refer to as Noble 2008 Prime, as well as pledges of the equity interests in NEP NY 2008's subsidiaries, which own our Altona, Chateaugay and Wethersfield windparks, and their assets (including the turbine supply agreements). NEP NY 2008's obligations under the loans also will be secured by a first priority pledge of the equity interests in NEP NY 2008 by EFS Noble II, LLC and GE Capital Markets, Inc., each a wholly-owned subsidiary of General Electric Capital Corporation.

    Certain Covenants and Events of Default

        The 2008 New York financing agreement contains a number of covenants including those that restrict, subject to certain exceptions, NEP NY 2008's ability to incur other debt or contingent liabilities, grant liens, sell or lease certain assets, make investments, lose or modify material permits, modify certain documents, enter into additional project contracts, dissolve, pay dividends and make other distributions and change its business. The 2008 New York financing agreement also includes customary affirmative covenants and events of default.

2008 Membership Interest Purchase and Equity Capital Contribution Agreement

        In June 2008, Noble 2008 Prime and NEP NY 2008 entered into a Membership Interest Purchase and Equity Capital Contribution Agreement, or the 2008 ECCA, with EFS Noble II, LLC and GE Capital Markets, Inc., each an affiliate of GE, which we refer to as EFS II and GECM, respectively. By executing the 2008 ECCA, EFS II and GECM committed, upon the satisfaction of certain conditions, to make equity capital contributions to NEP NY 2008, in exchange for Class A membership interests. Those conditions include, among others, the substantial completion of at least 90% of the expected number of wind turbines for our Altona, Chateaugay and Wethersfield windparks, a minimum number of which must qualify for the production tax credit in its current form, and satisfaction or waiver of all conditions to borrowing of the term loan under the 2008 New York financing agreement.

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        The 2008 ECCA provides for the equity capital contribution of EFS II and GECM to be made in up to two installments. The amount of the equity capital contribution to be made on the initial equity capital contribution date will be based on the number of wind turbines in our Altona, Chateaugay and Wethersfield windparks that have achieved substantial completion as of such date and whether the production tax credit has been extended or renewed in its current or modified form. If all of the wind turbines in our Altona, Chateaugay and Wethersfield windparks are not included for funding on the initial date, then any remaining wind turbines that achieve substantial completion will be funded on the second equity capital contribution date, which must occur prior to June 30, 2009.

        If the conditions to funding have otherwise been met, but one or more wind turbines subject to funding have been substantially completed after December 31, 2008, and at the time of funding the production tax credit has not been extended or renewed in its current or modified form, EFS II and GECM will be required to fully fund upfront their equity capital contribution with respect to those wind turbines based on the assumption that those wind turbines qualify for the production tax credit in its current form. EFS II and GECM will not be required to make any additional capital contributions with respect to any such wind turbines funded upfront. On the other hand, if the conditions to funding have otherwise been met, and at the time of funding an extension of the production tax credit in current or modified form has been enacted, the amount of the equity capital contribution of EFS II and GECM with respect to wind turbines substantially completed after December 31, 2008 will be based on the assumption that those wind turbines qualify for the production tax credit in its current or modified form, as the case may be. In such case, those wind turbines will be the subject of additional capital contributions in generally the same manner as wind turbines substantially completed on or before December 31, 2008.

        In connection with the execution of the 2008 ECCA, Noble Environmental Power, LLC issued a guaranty in favor of EFS II and GECM in support of Noble 2008 Prime's indemnification obligations under the 2008 ECCA, and any payment obligations of Noble 2008 Prime to EFS II or GECM under the New York 2008 LLC Agreement. The guaranty is capped, with respect to each of EFS II and GECM, at an amount equal to the equity capital contributions made by such investor, less any cash distributed to such investor under the New York 2008 LLC Agreement.

Additional Capital Contribution Agreement

        In June 2008, Noble 2008 Prime and NEP NY 2008 also entered into an Additional Capital Contribution Agreement, or ACCA, with EFS II and GECM. Pursuant to the ACCA, at the end of each fiscal quarter after the initial equity capital contribution date, EFS and GECM will be obligated to make additional cash capital contributions to NEP NY 2008 with respect to wind turbines that are eligible for the production tax credit in its current or modified form at the time they are substantially completed. A portion of each additional quarterly capital contribution amount will be fixed based on an agreed formula and payable regardless of the amount of eligible electricity generated by our Altona, Chateaugay and Wethersfield windparks in the applicable quarter. The remaining portion of each additional quarterly capital contribution amount will be contingent in amount based on the actual electricity generated by our Altona, Chateaugay and Wethersfield windparks that is eligible for production tax credits. The contingent portion of each additional quarterly capital contribution will be subject to a cap intended to comply with an IRS safe harbor for wind credit investment structures.

        The obligation of EFS II and GECM to make additional capital contributions to NEP NY 2008 will terminate on the earliest of (i) the latest expiration of the production tax credit period for any eligible wind turbine, (ii) the date the lenders under the 2008 New York financing agreement take title to the Class A membership interests following an exercise of remedies and (iii) the date EFS and GECM realize their target after-tax internal rate of return, but only if the term loan has been repaid.

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Amended and Restated Limited Liability Company Agreement

        Pursuant to the 2008 ECCA, on the date of term conversion, Noble 2008 Prime will enter into an Amended and Restated Limited Liability Company Agreement, or New York 2008 LLC Agreement, governing NEP NY 2008 in connection with the initial equity investment by EFS II and GECM in our Altona, Chateaugay and Wethersfield windparks. NEP NY 2008 holds all the interests in three subsidiary limited liability companies, or project companies, which hold the assets of our Altona, Chateaugay and Wethersfield windparks.

        The New York 2008 LLC Agreement will provide for two classes of membership interests, Class A membership interests and Class B membership interests. We expect that NEP 2008 Prime will hold 100% of the outstanding Class B membership interests, and EFS and GECM collectively will hold 100% of the outstanding Class A membership interests.

    Management

        Under the terms of the New York 2008 LLC Agreement, Noble 2008 Prime will be the managing member of NEP NY 2008 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 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 (described below), material actions will require the approval of Class A members holding 60% 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 economic interest. Material actions will include significant matters relating to the management and operation of NEP NY 2008 and the project companies and approval of an annual operating budget.

        As managing member, Noble 2008 Prime will be required to perform its obligations under the New York 2008 LLC Agreement in accordance with the terms of the agreement and the standards set forth therein. As managing member, Noble 2008 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 2008 and the project companies. In addition, in instances involving, directly or indirectly, the operation and management of our Altona, Chateaugay and Wethersfield windparks, including the supervision of affiliated and non-affiliated service providers, Noble 2008 Prime will be required to act in accordance with a prudent operator standard. In discharging its duties as managing member, Noble 2008 Prime will be permitted to rely on legal counsel, qualified industry consultants or other advisors. With respect to affiliated and non-affiliated service providers, Noble 2008 Prime's duties as managing member generally will be limited to supervising such persons, and Noble 2008 Prime generally will have no liability for the acts or selection of any service providers. Noble 2008 Prime will be able to be removed as managing member only for cause.

    Allocations and Distributions

        Profits, losses and other tax items (including production tax credits and accelerated tax depreciation) will be allocated 99% to the Class A members and 1% to the Class B member until the flip point occurs. Thereafter, profits, losses and other tax items generally will be allocated 6% to the Class A members and 94% to the Class B members. The "flip point" will be the date the Class A members realize the flip rate and either the term loan has been repaid or the ACCA has been terminated. The "flip rate" is a pre-determined after-tax internal rate of return, taking into account cash contributions and distributions as well as the tax benefits (primarily production tax credits 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

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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 2008 and the project companies.

        Distributable cash initially will be distributed 20% to the Class A members and 80% to the Class B member until the earliest of (a) the date the Class B member's capital account is first reduced to an amount equal to or less than 95% of NEP NY 2008's projected aggregate tax basis in its assets on the date of the projected flip point under certain probability modeling, (b) the date the Class B member's capital account is projected to reach such amount under such model with certain adjustments, and (c) the tenth anniversary of the initial equity capital contribution date. If the initial equity capital contribution date does not occur before December 31, 2008, or if it occurs after such date and prior to any extension or renewal of the production tax credit in its current or modified form, all distributable cash will be deposited into escrow, and no distributions will be made, until the earlier of the date, if any, the production tax credit is extended essentially in its current form or December 31, 2009.

        If under the 2008 ECCA the Class A members make a full, upfront equity capital contribution with respect to any wind turbine that reaches substantial completion after December 31, 2008 based on the assumption that the wind turbine qualifies for the production tax credit in its current form and (i) there is no extension or renewal of the production tax credit in its current or modified form enacted on or before December 31, 2009 or (ii) the production tax credit is extended or renewed in a modified form (e.g., different tax credit rate, different tax credit period) after the equity capital contribution date, and taking such events into account, the Class A members would not be projected to reach the flip rate on the tenth anniversary of the initial equity capital contribution date under certain probability modeling, the Class A members initially will be entitled to 100% of all cash distributions until the net present value of the cash they receive equals the net present value of the amount they would need to receive to reach the flip rate on the tenth anniversary of the initial equity capital contribution date, as shown in the modeling. See "—2008 Membership Interest Purchase and Equity Capital Contribution Agreement." After such date, cash would be distributed 20% to the Class A members and 80% to the Class B member until the earliest of (a) the date the Class B member's capital account is first reduced to an amount equal to or less than 95% of NEP NY 2008's projected aggregate tax basis in its assets on the date of the projected flip point as shown in the modeling and (b) the tenth anniversary of the initial equity capital contribution date.

        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 or the ACCA has been terminated, then 94% of the distributable cash will be used to service the term loan until either event occurs. After the flip point, cash will be distributed 6% to the Class A members and 94% to the Class B member.

    Indemnification Obligations

        The New York 2008 LLC Agreement will provide that any member who breaches, or who causes NEP NY 2008 to breach, any representation, warranty or covenant in the New York 2008 LLC Agreement may be held liable to any other member or NEP NY 2008 for any damages (including the value of any lost production tax credits) sustained by such person as a result of the breach. Claims for damages against the Class B member, other than damages for which a member is held directly liable to a third party, will be subject to a floor and a cap. All indemnification payments will be required to be made on an after-tax basis, and all distributions otherwise payable to the indemnifying party will be required to be redirected and paid over to the indemnified party. In the event of any dispute, any distributions otherwise payable to the indemnifying party will be required to be deposited into escrow pending resolution of the dispute.

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        In addition, the members will make certain covenants to each other, the breach of which could result in indemnification obligations to NEP NY 2008, the project companies and/or other members, including:

    Related Party Problems.  Only wind energy sold to unrelated parties qualifies for the production tax credit. Accordingly, to avoid potential related party problems, as managing member, Noble 2008 Prime is obligated to notify the members prior to entering into any power sales agreement. If Noble 2008 Prime fails to notify the members as required and, as a result, any member becomes a related party, Noble 2008 Prime is obligated to indemnify the members for any damages (including the value of lost production tax credits) 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 is obligated to indemnify NEP NY 2008, the project company and the other members for any damages (including the value of lost production tax credits) suffered as a result.

    Array Loss.  The Class B member has agreed not to develop or construct any windpark, other than our windparks in operation in Clinton and Ellenburg, within 15 rotor diameters of our Altona, Chateaugay and Wethersfield windparks if it could reasonably be expected to result in a 1.0% or greater reduction of the net annual energy output of our Altona, Chateaugay and Wethersfield windparks, unless the Class B member agrees to compensate the affected windpark for any damages. If the reduction could reasonably be expected to be 2.0% or greater, the Class B member is required to obtain the approval of a majority of the Class A members.

        These indemnification rights and obligations will not be exclusive and will be in addition to any rights and remedies available to NEP NY 2008, the project company or the members at law or in equity.

    Transfers

        Under the terms of the New York 2008 LLC Agreement, the members' ability to transfer their interests in NEP NY 2008 will be subject to general restrictions, including prohibitions on the transfer of interests to competitors of NEP NY 2008, persons adverse to NEP NY 2008 or the project companies, persons who purchase electricity from NEP NY 2008 and other disqualified transferees. In addition, the New York 2008 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 interest to a transferee that meets minimum credit rating requirements and who expressly assumes the Class A member's obligations under the ACCA. These same restrictions also apply to the transfer of controlling interests in the members.

        If any member proposes to transfer all or part of its membership interest other than in a permitted disposition and certain other dispositions, the other members, prior to the flip point, and the Class B member, after the flip point, will have the right to make an unconditional offer to purchase the membership interest. After the flip point, if the Class B member proposes to dispose of its Class B membership interest pursuant to a bona fide third-party offer, the Class B member will have the right to force the Class A members to join the sale on the same terms and conditions as the Class B member. If the Class B member does not elect to exercise these drag-along rights, the Class A members will have the right to dispose of their Class A membership interests to the third-party purchaser on the same terms and conditions as the Class B member and the Class B member will be prohibited from consummating the sale unless the third-party agrees to purchase all of the membership interests offered for sale by the Class B member and Class A members.

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    Redemption and Buyout Rights

        The New York 2008 LLC Agreement will provide that the Class B member has 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 2008 LLC Agreement, and on each 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 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 2008 LLC Agreement and, in certain circumstances, to cause the redemption of a Class A member that objects to any material action requiring its consent. In the case of any such redemption, the Class B member is required to contribute sufficient cash to NEP NY 2008 necessary to enable NEP NY 2008 to redeem the Class A member or members for an amount equal to the greatest of (i) 110% of fair market value, (ii) 110% of the amount necessary to cause the redeemed Class A members to realize the flip rate and (iii) an amount equal to the aggregate capital account balances of the redeemed Class A members.

        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. All members will have the right to acquire for 75% of fair market value the membership interests of any member that commits fraud or willful misconduct in its capacity as a member.

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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. According to the Energy Information Administration, 37% of new U.S. power generation capacity in 2007 consisted 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 between 9% and 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.

        According to the U.S. Department of State, 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 renewable portfolio standard programs, as well as federal tax incentives including production tax credits 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 36 of the 50 states. As depicted on the maps on the next page, the total installed capacity of U.S. windparks increased by over 680% from 2,500 MW to over 19,500 MW between December 1999 and June 2008.

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GRAPHIC

GRAPHIC

Source for December, 1999: U.S. Department of Energy.

Source for June, 2008: American Wind Energy Association.

        According to the U.S. Department of Energy, installed U.S. wind capacity increased by 2,426 MW (27%) in 2006, and by 5,021 MW (43%) in 2007. Despite this growth, wind energy generation still only represented just under 1% of U.S. electricity supply in 2007, and we believe that the prospects for further growth are very favorable. Additionally, in May 2008, the U.S. Department of Energy published a feasibility report discussing the potential for wind power to provide up to 20% of U.S. electricity needs by 2030, which would require over 300,000 MW of cumulative installed wind capacity to meet this target. 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: Forecasts are from Emerging Energy Research, June 2007 and historical figures are from U.S. Department of Energy-National Renewable Energy Laboratory, December 31, 2000 and December 31, 2005.

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

        The demand for electricity has historically exhibited steady growth and has increased by a cumulative amount of 23% or 728 billion kWh from 1995 through 2007. According to the Energy Information Administration, 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 21%, respectively, of U.S. electrical power generation in 2007. In New York, New England, Texas and California, natural gas accounts for a significant portion of the 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 January 1, 1998 to June 30, 2008, the average price of natural gas increased by approximately 382%, while the average price of oil increased by 673% 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 and for the six month period beginning January 1, 2008 to June 30, 2008.

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: National Association of Regulatory Utility Commissioners. For each generation source, cost is calculated by taking the mid-point of the range described in the report by Lazard — "Levelized Cost of Energy Analysis — Version 2.0," June 2008


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 and volatility 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 Energy Information Administration, 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. Such legislation and regulations have been designed to, for example, reduce ozone concentrations, particulate emissions, haze and mercury emissions and 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.

        We believe there is significant support in the United States to enact legislation that 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 United States 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.

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

        Growth in the U.S. 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 renewable portfolio standard 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 renewable energy certificates 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 renewable portfolio standard programs has doubled in the last six years and as of August 2008, 32 states and the District of Columbia had adopted some form of renewable portfolio standard program. The District of Columbia and 26 of the 32 states have mandatory renewable portfolio standard requirements and combined, these 26 states represent over 50% of total U.S. electrical load. A number of states, including Arizona, California, Colorado, Massachusetts, Nevada, New Jersey, New Mexico and Texas have been so successful in meeting their original renewable portfolio standard 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 renewable portfolio standard programs or set state goals, as well as the related requirements or targets, are set forth in the following map.


U.S. Renewable Portfolio Standard Programs and Goals for Renewable Energy Generation

         GRAPHIC

    Source: Database of State Incentives for Renewables & Efficiency, August 2008.

    1.
    RE – Renewable Energy.
    2.
    IOUs – Investor-Owned Utilities.
    3.
    Xcel – Xcel Energy, an electric and gas company that operates in the Midwest.
    4.
    Class I Renewables – Electricity derived from solar, wind, wave or tidal action, geothermal, landfill gas, anaerobic digestion, fuel cells using renewable fuels, and certain other forms of sustainable biomass.
    5.
    Co-op – Customer-owned electric utility that distributes electricity to its members.
    6.
    Munis – Municipalities.

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

    Renewable Energy Certificates.  A renewable energy certificate 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 renewable energy certificates to track and verify compliance with their renewable portfolio standard programs. Retail energy suppliers can meet the requirements by purchasing renewable energy certificates from renewable energy generators, in addition to producing or acquiring the electricity from renewable sources. Under many renewable portfolio standard programs, energy providers that fail to meet renewable portfolio standard requirements are assessed a penalty for the shortfall, usually known as an alternative compliance payment. Because renewable energy certificates can be purchased to satisfy the renewable portfolio standard requirements and avoid an alternative compliance payment, the amount of the alternative compliance payment effectively sets a cap on renewable energy certificate prices. In situations where renewable energy certificate supply is short, renewable energy certificate prices approach the alternative compliance payment, which in several states is in the $50-$59/MWh range. As a result, renewable energy certificate prices can rival the price of energy and renewable energy certificates can represent a significant additional revenue stream for wind energy generators.

    Production Tax Credits.  The production tax credit 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 production tax credit was $20/MWh. Wind energy generators with insufficient taxable income to benefit from the production tax credit may take advantage of a variety of investment structures to monetize the tax benefits.

      The production tax credit was originally enacted in 1992 for windparks placed into service after December 31, 1993 and before July 1, 1999. The production tax credit 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 production tax credit 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 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 the modified accelerated cost recovery system, a significant portion of windpark assets is deemed to have depreciable life of five years which is substantially shorter than the 15 to 20 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 production tax credits, through forming a limited liability company with third parties.

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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 electricity for 20 to 30 years.

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

    According to the Danish Wind Industry Association and the U.S. Department of Energy, 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, according to the U.S. Department of Energy, as turbines installed in 2004 through 2006 averaged a 33%-35% 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% 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 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—National Renewable Energy Laboratory.

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 energy 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;

    Renewable energy certificate sales.  In many states, conventional energy producers are required either to produce a certain percentage of their energy from renewable sources or to purchase renewable energy certificates from renewable energy producers. Renewable energy certificates represent the environmental attributes associated with electricity from renewable sources. Renewable energy certificates 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 an independent 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 programs and active renewable energy certificate markets. Through renewable portfolio standard programs and renewable energy certificate 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 power generation sales while allowing us to benefit from future increases in energy prices.

        We were founded in August 2004 and, while we did not generate revenue until May 2008, our business expanded in many ways during the intervening period. In particular, we grew our land rights from zero to over 400,000 acres, acquired a number of development and construction permits, transmission queue positions, and meteorological data as well as contracted to purchase 1,210 turbines from GE. Our development progress facilitated the construction and operation of our Initial New York Windparks and will facilitate the construction and operation of windparks expected to come online during the remainder of 2008 and in future years. We also plan to continue to grow our pipeline over the next several years at a rate which maintains or increases the size of the development portfolio. 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 3,851 MW of capacity as we further expand into attractive wind energy markets in Maine, Michigan, Minnesota, New Hampshire, Vermont, Pennsylvania and Wyoming. In addition, we continuously identify and evaluate new windparks as part of our core business strategy. Windpark project development is one of our core strengths and areas of focus. Based on our historical success in identifying sites for potential 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 have grown into a fully integrated wind energy company with 179 employees and 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.

        We currently have contracts in place with General Electric, or GE, to purchase all to the turbines required for all of our windparks slated for construction through 2009 as well as turbines representing 71% of the MW needed to support our windparks slated for construction in 2010. We believe that our performance under the five turbine supply agreements that we have entered into with GE (representing a total of 1,815.0 MW of turbines) will assist us in obtaining additional turbines for 2010 and subsequent years.

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        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 existing turbine supply agreements provide us with the knowledge and resources necessary to rapidly grow our windpark portfolio.


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 1,204 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 as well as turbines representing 71% of the MW needed to support our windparks slated for construction in 2010.

        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.

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    Active Renewable Energy Certificate Markets.  We also look at whether the state or region in which the potential site will be located has a renewable portfolio standard program that presents an opportunity to generate additional revenues through the sale of renewable energy certificates. 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).

    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 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 environmental impact study 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 environmental impact study 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
  Independent
System
Operator

  Capacity (MW)
  Liquid
Energy
Market

  Renewable
Energy
Certificate
Market

  Capacity
Market

  Land
Control

  Transmission
Study
Commenced
or Completed

  Met Data
Available

  Turbines
Secured

  Environmental
Impact
Study/
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                                
           
                               
Windparks Under Construction                                            
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/Villenova   NY   NYISO   94.5   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   159.0   ü   ü     ü   ü   ü   ü  
           
                               
  Capacity Subtotal           499.5                                
           
                               
2010 Windparks                                            
Burke   NY   NYISO   60.0   ü   ü   ü   ü   ü   ü   ü  
Farmersville   NY   NYISO   100.5   ü   ü   ü   ü   ü   ü   ü  
Mitchell County I (Phase II)   TX   ERCOT   141.0   ü   ü     ü   ü   ü   ü  
Mitchell County II   TX   ERCOT   150.0   ü   ü     ü   ü   ü      (1)  
Grandpa's Knob   VT   ISONE   50.0   ü   ü   ü   ü   ü   ü    
Granite Reliable   NH   ISONE   74.0   ü   ü   ü   ü   ü   ü    
Flat Hill I   MN   MISO   129.0   ü   ü     ü     ü   ü  
           
                               
  Expected Capacity Subtotal           704.5                                
           
                               
  Expected Total Capacity through 2010           1,951.0                                
           
                               
2011/2012 Windparks                                            
Expansion of existing windparks           270.0                                
New windparks in existing states           910.0                                
Windparks in new states           720.0                                
           
                               
  Estimated Capacity Subtotal           1,900.0                                
           
                               
  Estimated Total Capacity through 2012           3,851.0                                
           
                               

(1)
Turbines representing 70 MW have been allocated to this windpark.

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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   120
Michigan   400
Minnesota   270
New York   180
Texas   650
Vermont   80
Wyoming   100
Pennsylvania   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, Pennsylvania 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 many of these projects, we have secured a portion of the land necessary to place our turbines; have analyzed the characteristics of the applicable energy, capacity and renewable energy certificate markets; 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 3,851 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 15 years of experience with complex power and infrastructure projects;

    All of the turbines secured to support our windparks slated for construction through 2009 and turbines secured representing 71% of the MW needed to support our windparks slated for construction in 2010; 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 704.5 MW of capacity. By the end of 2012, we expect to have operational projects representing 3,851 MW of capacity in Maine, Michigan, Minnesota, New Hampshire, New York, Pennsylvania, 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 15 years of experience with complex power and infrastructure 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 15 years of experience and involvement in bringing domestic and international power and infrastructure 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 engineering and construction and operations and maintenance 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.

All of the turbines secured to support our windparks slated for construction through 2009 and turbines secured representing 71% of the MW needed to support our windparks slated for construction in 2010

        Our turbine procurement strategy is focused on maintaining relationships with those turbine suppliers who have proven track records, access to supply chain materials and experienced installation, service and support personnel. We have successfully secured all of the turbines needed to support our windparks slated for construction through 2009 as well as turbines representing 71% of the MW needed to support our windparks slated for construction in 2010 from GE. With over 8,500 1.5 MW wind turbines installed worldwide, we believe GE turbines have an established track record and a solid history of reliability. We believe that our performance under the five turbine supply agreements that we have entered into with GE (representing a total of 1,815.0 MW of turbines) combined with the fact that a GE subsidiary is a tax equity investor in our Initial New York Windparks and will be a tax equity investor in our Altona, Chateaugay and Wethersfield windparks that are currently under construction in New York, and the number of members of our management team who were previously employed by GE, will strengthen our ability to enter into turbine supply agreements with GE on acceptable terms in the future. In addition to GE, we maintain an active dialogue with Vestas, and as we continue to grow our portfolio, we plan to develop additional relationships with other major turbine suppliers. We believe that our existing turbine supply agreements, scale and experience will enable us to continue to secure the turbines and related spare parts necessary to support our growth.

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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 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 renewable portfolio standard 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 the

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Electric Reliability Council of Texas, 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 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)

  Renewable Portfolio Standard
Energy Target

  2007 Renewable
Energy
Certificate
Prices

  Separate Capacity Market
  2006 Capacity Price ($/kW-mo.)
  Actual 2006 Reserve Margin
Michigan   8.60¢   None   Not available   No   Not applicable   18%(9)

Minnesota

 

7.36¢

 

25% by 2025

 

Not available

 

No

 

Not applicable

 

18%(9)

Maine

 

13.26¢

 

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

 

$54(2)

 

Yes

 

$4.50(6)

 

10%(10)

New Hampshire

 

13.96¢

 

23.8% in 2025

 

$54(2)

 

Yes

 

$4.50(6)

 

10%(10)

Vermont

 

11.99¢

 

Renewable energy meets any
increase in retail sales by 2012; 20% by 2017

 

$54(2)

 

Yes

 

$4.50(6)

 

10%(10)

New York

 

15.35¢

 

24% by 2013

 

$15(3)

 

Yes

 

$2.61(7)

 

17%(11)

Texas

 

10.27¢

 

5,880 MW by 2015

 

$4(4)

 

No

 

Not applicable

 

14%(12)

Wyoming

 

5.27¢

 

None

 

Not available

 

No

 

Not applicable

 

24%(13)

Pennsylvania

 

9.07¢

 

18% by 2020

 

$12(5)

 

Yes

 

$3.35(8)

 

14%(14)

Source: Average Retail Electricity Prices from the Energy Information Administration; New York capacity prices from ESAI Capacity Watch, March 2008; New England capacity prices from ISO-NE; Pennsylvania capacity prices from PJM Interconnection; renewable portfolio standard targets from the Database of State Incentives for Renewables & Efficiency, April 2008; renewable energy certificates prices from Evolution Markets Inc. 2006 reserve margins from 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)
2008 New Jersey Class 1 average renewable energy certificate price as reported by Evolution Markets Inc.
(6)
Represents the ISO New England forward capacity market results for 2010/2011.
(7)
Represents the New York Rest of State 2007 monthly average spot market installed capacity price.
(8)
Represents the PJM 2011/2012 RPM base residual auction results.
(9)
Summer peaking reserve margin for the Midwest Independent System Operator.
(10)
Summer peaking reserve margin for ISO New England.
(11)
Summer peaking reserve margin for the New York Independent System Operator.
(12)
Summer peaking reserve margin for the Southwest Power Pool and the Electric Reliability Council of Texas (14% in 2007 for the Electric Reliability Council of Texas)
(13)
Summer peaking reserve margin for the Southwest for 2005.
(14)
Summer peaking reseve margin for PJM Interconnection.

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

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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, 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 power generation sales 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 in advance of the closing of financing for a windpark allows us to potentially benefit from future energy price movements and avoid the cost and price competition involved in bidding on power purchase agreements. 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.

        Our financial hedge activity is limited by the term for which counterparties are willing to provide hedges, the willingness of such counterparties to accept project credit risk and the number of counterparties willing to enter in these transactions. While we have some flexibility to determine the time at which we enter into these financial hedges, we are often constrained by the timing requirements of our financing arrangements. 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 use tax equity financing arrangements in order to monetize the value

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generated by production tax credits and accelerated tax depreciation that are available to us as a wind energy generator. We are 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.

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.

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GRAPHIC

Development

    Site Selection, Land Control and Permitting

        Our development professionals select areas for development, first by evaluating regional energy, renewable energy certificate 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 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.

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        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 energy 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, as measured over ten years, 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 net energy output in MWh measured at the revenue meter over a period of time, divided by the theoretical energy output of the windpark in the measurement period.

        For each wind turbine in a windpark, the annual gross energy output is calculated by multiplying (i) the cumulative number of hours in a typical year that the wind blows at a given speed by (ii) the power output, expressed in MW, of a wind turbine at each given speed (based on the manufacturer's specification), and repeating this for all relevant wind speeds.

        Once this annual gross energy output for a single turbine has been determined, a number of adjustments are made to reflect the estimated loss of productivity from a variety of causes, including wake or array losses, which reflect the impact of neighboring wind turbine generators, availability, inefficiency of the electrical delivery system of the windpark, turbulence or abnormal wind speeds and unusual ambient temperatures. These adjustments result in a projected net energy output of a single

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turbine. The net energy output for each wind turbine is then added together to calculate the net annual energy output of the windpark.

        The theoretical maximum annual energy output of a wind turbine is calculated by multiplying the total capacity of the wind turbine by the number of hours in a year. For example, a 1.5 MW turbine's theoretical maximum annual energy output is 13,140 MWh (1.5 MW multiplied by 24 hours per day multiplied by 365 days in a year). Therefore, assuming an illustrative net annual energy output for a single wind turbine (after adjusting for any productivity reductions) is 4,500 MWh, the resulting net capacity factor would be 34.2% (4,500/13,140).

        In reality, the wind speed frequency distribution at each wind turbine varies from year to year. As a result, we use available historical data to estimate the average energy production which may be experienced over a period of at least 10 years.

        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 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.