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**UNITED STATES
SECURITIES AND EXCHANGE COMMISSION**Washington, D.C. 20549**FORM 20-F** (Mark One) [   ]
     REGISTRATION STATEMENT PURSUANT TO SECTION 12 (b) OR (g)OF THE SECURITIES EXCHANGE ACT OF 1934 (THE "EXCHANGE ACT")OR[ X ]
     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THEEXCHANGE ACTFor the fiscal year ended June 30, 2010.OR[   ]
     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OFTHE EXCHANGE ACTFor the transition period from _______ to _______OR[   ]
     SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE EXCHANGE ACTDate of event requiring this shell company report _______
  Commission file number 000-49917 NEVADA GEOTHERMAL POWER INC.(Exact name of Registrant as specified in its charter) Not Applicable(Translation of Registrant's name into English) British Columbia, Canada(Jurisdiction of incorporation or organization) 900-409 Granville Street, Vancouver, British Columbia, Canada, V6C 1T2(Address of principal executive offices) Name: Andrew T. Studley; Telephone: 604-688-1553; Email:info@nevadageothermal.com; Facsimile: 604-688-5926; Address: 900-409 Granville Street,
Vancouver, British Columbia, Canada, V6C 1T2(Name, Telephone, E-mail, and/or Facsimile number and Address of Company Contact Person) Securities registered or to be registered pursuant to Section 12(b) of the Act: Title of each class
     Name of each exchange on which registeredNot Applicable
     Not Applicable
  Securities registered or to be registered pursuant to Section 12(g) of the Act. Common Shares Without Par Value
(Title of Class) Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. None
(Title of Class)


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2 Indicate the number of outstanding shares of each of the issuers classes of capital or common stock as of the close of the period covered by the annual report. The number of outstanding common
shares as of November 30, 2010 is116,311,504 Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act YES [   ] NO [X ] If this report is an annual or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. YES [   ] NO [X ] Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections. Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES[X ]NO [   ] Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act Large accelerated filer  [   ]
     Accelerated filer [   ]
     Non-accelerated filer [X ]
 Indicate by check mark which financial statement item the Registrant has elected to follow. U.S. GAAP  [   ]
     International Financial Reporting Standards as issued by the International **Accounting Standards Board.**
     Other [ X ]
  If Other has been checked in response to the previous question, Indicate by check mark which financial statement item the Registrant has elected to follow. [ X ]Item 17 [   ] Item 18 If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [   ] NO  [X ] (APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS) Indicate by check mark whether the Registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Exchange Act subsequent to the distribution of securities under a plan confirmed by a court. Not Applicable YES [   ] NO [   ]


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3 TABLE OF CONTENTS Page No. Forward Looking Statements
     6Presentation of Financial Information and Other Information
     7PART IITEM 1
     Identity of Directors, Senior Management and Advisers
     7ITEM 2
     Offer Statistics and Expected Timetable
     8ITEM 3
     Key Information
     8A.
     Selected Financial Data
     8B.
     Capitalization and Indebtedness
     10C.
     Reasons For The Offer and Use of Proceeds
     10D.
     Risk Factors
     10ITEM 4
     Information on the Company
     21A.
     History and Development of the Company
     21B.
     Business Overview
     22C.
     Organizational Structure
     29D.
     Property, Plants and Equipment
     30ITEM 4A
     Unresolved Staff Comments
     55ITEM 5
     Operating and Financial Review and Prospects
     55A.
     Operating Results
     55B.
     Liquidity and Capital Resources
     62C.
     Research and Development, Patents and Licenses, etc.
     67D.
     Trend Information
     67E.
     Off-Balance Sheet Arrangements
     67F.
     Tabular Disclosure of Contractual Obligations
     68ITEM 6
     Directors, Senior Management and Employees
     68A.
     Directors and Senior Management
     68B.
     Compensation
     73C.
     Board Practices
     76D.
     Employees
     78E.
     Share Ownership
     78ITEM 7
     Major Shareholders and Related Party Transactions
     80A.
     Major Shareholders
     80B.
     Related Party Transactions
     81C.
     Interests of Experts and Counsel
     82


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4 ITEM 8
     Financial Information
     83A.
     Consolidated Statements and Other Financial Information
     83B.
     Significant Changes
     83ITEM 9
     The Offer and Listing
     84A.
     Offer and Listing Details
     84B.
     Plan of Distribution
     85C.
     Markets
     85D.
     Selling Shareholders
     85E.
     Dilution
     85F.
     Expenses of the Issue
     85ITEM 10
     Additional Information
     86A.
     Share Capital
     86B.
     Memorandum and Articles of Association
     86C.
     Material Contracts
     88D.
     Exchange Controls
     90E.
     Taxation
     92F.
     Dividends and Paying Agents
     101G.
     Statement by Experts
     101H.
     Documents on Display
     101I.
     Subsidiary Information
     102ITEM 11
     Quantitative and Qualitative Disclosures About Market Risk
     102ITEM 12
     Description of Securities Other Than Equity Securities
     104PART IIITEM 13
     Defaults, Dividend Arrearages and Delinquencies
     104ITEM 14
     Material Modifications to the Rights of Security Holders and Use ofProceeds
     104ITEM 15
     Controls and Procedures
     104ITEM 16A
     Audit Committee Financial Expert
     106ITEM 16B
     Code of Ethics
     106ITEM 16C
     Principal Accountant Fees and Services
     107ITEM 16D
     Exemptions from the Listing Standards for Audit Committees
     108ITEM 16E
     Purchases of Equity Securities by the Issuer and Affiliated Purchasers
     108ITEM 16F
     Change in Registrants Certifying Accountant
     108


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5 ITEM 16G
     Corporate Governance
     108PART IIIITEM 17
     Financial Statements
     108ITEM 18
     Financial Statements
     109ITEM 19
     Exhibits
     110Signatures
     125


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6

FORWARD-LOOKING STATEMENTS

This Annual Report contains forward-looking statements as that term is defined in the Private Securities Litigation Reform Act of 1995. These statements relate to future events or our future financial performance. In some cases, you can identify forward-looking statements by terminology such as "may", "will", "should", "expects", "plans", "anticipates", "believes", "estimates", "predicts", "potential" or "continue" or the negative of these terms or other comparable terminology. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks in the section entitled "Risk Factors that may cause our or our industry's actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by these forward-looking statements. Such statements include, but are not limited to,

The nature of geothermal energy exploration and potential exploitable reserves;Our business strategy;Our ability to obtain future capital and financings on acceptable terms;Our plans to obtain adequate partners to assist in future development;Our expected commencement and completion dates related to resource production operations; andOur overall plans, objectives, expectations and limitations.


Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements to actual results. Many factors could cause our actual results, performance or achievements to be materially different from any future results, performance, or achievements that may be expressed or implied by such forward-looking statements, including, among others:

- Our ability to obtain the substantial capital required to continue exploration and operations;
- Our lack of significant production revenues and history of operating losses;
- Our ability to find and enter into agreements with potential partners;
- Our ability to attract and retain key personnel;
- Further equity financing may substantially dilute the interests of our shareholders; |
- Changing market conditions; and

6

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7 Other risks detailed from time-to-time in our ongoing filings, annual information forms and annual reports and filings with Canadian securities regulators and the United States Securities and Exchange Commission under the heading Risk Factors. PRESENTATION OF FINANCIAL INFORMATION AND OTHER INFORMATION As used in this Annual Report, the terms "we", "us", "our", Company, "NGP" and NGP Inc. mean Nevada Geothermal Power Inc. and our subsidiaries, unless otherwise indicated. Our wholly-owned subsidiaries, Nevada Geothermal Power US Holdings Inc., Nevada Geothermal Power Company, Desert Valley Gold Company, Blue Mountain Power Company Inc., Nevada Geothermal Power Chile S.A., Nevada Geothermal Operating Company LLC, Nevada Geothermal Power Holding Company LLC, NGP Blue Mountain Holdco LLC, NGP Blue Mountain Holdco II LLC, NGP Blue Mountain Holdco III LLC, NGP Blue Mountain Holdco IV LLC, NGP Blue Mountain I LLC, NGP Blue Mountain II LLC, NGP Blue Mountain III LLC, NGP Blue Mountain IV LLC, NGP (Crump 1), NGP (Pumpernickel 1), and NGP (Black Warrior 1) are referred to in this Annual Report as "NGP US, NGPC", Desert Valley Gold, "Blue Mountain Company", NGP Chile, NGOC, Holdings,Holdco, Holdco II, Holdco III, Holdco IV, NGP I, NGPII, NGPIII, NGPIV, Crump, Pumpernickel and Black Warrior respectively. Unless otherwise indicated, all dollar amounts referred to herein are in US dollars. The information set forth in this Annual Report on Form 20-F is as of June 30, 2010 unless an earlier or later date is indicated. Financial information is presented in accordance with accounting principles generally accepted in Canada. Measurement differences between accounting principles generally accepted in Canada and in the United States, as applicable to Nevada Geothermal Power Inc., are set forth in Item 5 of this Annual Report and in Note 22 the accompanying Consolidated Financial Statements of Nevada Geothermal Power Inc. Statements in this Annual Report regarding expected completion dates and anticipated commencement dates of resource production operations, projected quantities of future resource production and anticipated production rates, operating efficiencies, costs and capital expenditures, as well as their timing are forward-looking statements. Actual results could differ materially depending upon the availability of materials, equipment, required permits or approvals and financing, the occurrence of unusual weather or operating conditions, the accuracy of reserve estimates, lower than expected results or the failure of equipment or processes to operate in accordance with specifications. See "Risk Factors" for other factors that may affect our future financial performance. PART I ITEM 1 Identity of Directors, Senior Management and Advisers This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. 7


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8 ITEM 2 Offer Statistics and Expected Timetable This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. ITEM 3 Key Information **A. Selected Financial Data**  The selected historic financial information may not be indicative of our future performance and should be read in conjunction with Item 5  Operating and Financial Review and Prospects and the consolidated financial statements and the notes attached to those financial statements included elsewhere in this Annual Report. Note 22 of the Consolidated Financial Statements included with these filing sets forth the measurement differences were such information to be presented in conformity with United States generally accepted accounting principles (United States GAAP). Results for the year ended June 30, 2010, are not necessarily indicative of results for future periods. Information in accordance with Canadian GAAP: Year Ended June 302010
     2009
     2008
     2007
     2006Total revenue
     $11,839,010
     $0
     $0
     $0
     $0Net (loss)Total
     $(17,981,451)
     $(5,088,760)
     $(3,425,767)
     $(2,538,389)
     $(1,388,490)Per Share
     $(0.19)
     $(0.05)
     $(0.04)
     $(0.30)
     $(1.03)Total assets
     $187,273,781
     $222,810,846
     $81,418,879
     $37,374,414
     $23,056,369Total short-term liabilties
     $156,951,454
     $175,561,911
     $10,540,410
     $2,758,157
     $1,790,782Total  long-term liabilities
     $4,532,691
     $4,706,155
     $21,957,968
     $398,326
     $0Capital stock
     $54,942,619
     $53,857,748
     $53,701,819
     $36,875,324
     $25,525,985Weighted average number of shares
     95,280,808
     94,438,849
     79,122,910
     61,294,757
     36,537,557Total shareholders' equity (deficiency)
     $25,789,636
     $42,542,780
     $48,920,501
     $34,217,929
     $21,271,822Cash dividends declared per share
     Nil
     Nil
     Nil
     Nil
     NilNumber of Shares
     95,576,504
     94,547,504
     94,169,504
     76,824,1714
     53,202,171
  8


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9 Information in accordance with United States GAAP: Year Ended June 302010
     2009
     2008
     2007
     2006Total revenue
     $11,839,010
     $0
     $0
     $0
     $0Net LossTotal
     $(16,723,009)
     $(7,292,803)
     $(29,168,212)
     $(16,447,040)
     $(5,802,846)Per Share
     $(0.18)
     $(0.08)
     $(0.37)
     $(0.27)
     $(0.16)Total assets
     $139,054,680
     $173,333,303
     $31,167,953
     $13,739,557
     $14,639,587Total short-term liabilties
     $156,951,454
     $175,561,911
     $10,540,410
     $2,758,157
     $1,790,782Total long-term liabilities
     $4,532,691
     $4,706,155
     $21,957,968
     $398,326
     $0Capital stock
     $54,942,619
     $53,857,748
     $53,701,819
     $36,875,234
     $25,525,985Weighted average number of shares
     95,280,808
     94,438,849
     79,122,910
     61,294,757
     36,537,557Total shareholders' equity (deficiency)
     $(22,429,465)
     $(6,934,763)
     $(1,330,425)
     $10,583,074
     $12,855,040Cash dividends declared per share
     Nil
     Nil
     Nil
     Nil
     NilNumber of Shares
     95,576,504
     94,547,504
     94,169,504
     76,824,171
     53,202,171 We calculate loss per share using the treasury stock method. Under the treasury stock method, only instruments with exercise amounts less than market prices impact the diluted calculations. In computing diluted loss per share, no shares were added to the weighted average number of common shares outstanding as the effect of potentially issuable common shares is anti-dilutive. Disclosure of Exchange Rate History On December 1, 2010, the exchange rate in effect for Canadian dollars exchanged for United States dollars, expressed in terms of Canadian dollars, based on the noon buying rates in New York City, for cable transfers in Canadian dollars, as certified for customs purposes by the Federal Reserve board was $1.0160. For the past five fiscal years ended June 30, 2010, and for the period between July 1, 2010 and November 30, 2010 (calculated monthly), the following exchange rates were in effect for Canadian dollars exchanged for United States dollars, expressed in terms of Canadian dollars and based upon the exchange rate as determined above: Year/Month End
     
     AverageYear:June 30, 2006
     
     $1.1562June 30, 2007
     
     $1.1322June 30, 2008
     
     $1.0102June 30, 2009
     
     $1.1658June 30, 2010
     
     $1.0559
  9


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10 Month:
     Low/HighJuly, 2010
     1.0678/1.0256August, 2010
     1.0674/1.0108September, 2010
     1.0604/1.0216October, 2010
     1.0374/0.9986November, 2010
     1.0286/0.9980
  B. Capitalization and Indebtedness
 
  C. Reasons for the Offer and Use of Proceeds
 
  D. Risk Factors
  This Annual Report contains forward-looking statements that involve risk and uncertainties. Our actual results may differ materially from the results discussed in the forward-looking statements. The following is a brief discussion of those distinctive or special characteristics of our operations and industry which may have a material impact on, or constitute risk factors in respect of our future financial performance. You should carefully consider the following risks and uncertainties in addition to other information in this Annual Report in evaluating our Company and our business before purchasing shares of our Company's common shares. In addition to those discussed elsewhere in this Annual Report, our business, operating and financial condition could be affected due to any of the following risks. Risks Relating to our Business The search for geothermal energy, as a business, is risky. We can provide investors with no assurance that our property interests, other than Blue Mountain, contain commercially exploitable reserves. Exploration is a speculative venture necessarily involving substantial risk. As of the date of this Form 20-F there are several significant issues concerning the Blue Mountain project which are expected to be resolved during the first half of 2011, however the outcome of each of these issues is uncertain at this time. Blue Mountain Risks  Uncertainty Concerning Ability to Comply with Terms of the Power Purchase Agreement with NV Energy In October 2009 the Company completed construction and testing of its power plant at Blue Mountain in Nevada, USA to capitalize on geothermal resources estimated by an independent geothermal consulting company of supporting 40 net MW power generation (90% statistical probability); however, a model of the geothermal reservoir prepared by the consultant indicates additional wells will be required to reach and sustain the target power production. In August 2009, the Companys Blue Mountain subsidiary, NGP 1, began supplying power to NV Energy (NVE) under a power purchase agreement (PPA) at 60% - 80% of the 10


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11 anticipated 40 (net) MW target. During November 2009 NGP 1 declared Commercial Operation under the PPA, committing to supply the minimum 36.1 MW that is required during 2010. NGP 1 also continued drilling additional wells and despite a first calendar quarter electrical wiring issue, during which NGP 1 declared Force Majeure, successful drilling resulted in an increase in power production to the PPA minimum by the end of March, averaging 37 and 34 MW respectively during the second and third calendar quarters. The third quarter average of 34 MW was affected by a July pump failure. The Company is committed to supplying a minimum number of portfolio credits (PCs which are similar to Renewable Energy Credits (RECS)) to NVE during a contract year, which runs from January to December. During the third calendar quarter NVE challenged the above referenced Force Majeure claim, raising the possibility, if the challenge is successful, of a liability for NVEs replacement cost for the shortfall in PCs supplied. The Company believes that the Force Majeure challenge has no merit and also that the potential liability is small, however in the event that the Force Majeure claim is denied, the amount of the potential liability will depend upon the actual shortfall in PCs produced in the year to December 31, 2010 and also the price NVE pays for PCs when they purchase replacement PCs. The Company has not been able to obtain an estimate of the potential liability from NVE, and accordingly there is uncertainty regarding both the existence and the amount of a potential liability. Modelling of the Blue Mountain reservoir indicates that reinjection of cooled geothermal brine will gradually decrease the reservoir temperature and therefore, with the current wells, plant power production will decrease approximately 2.5% per year. The PPA provides for 3% reduction per year and to ensure compliance with its PPA the Company is limiting power production, having committed to John Hancock that it will nominate and supply the PPA minimum until it can demonstrate sustainable production at higher levels. Accordingly, the Company has nominated 35 MW power production during 2011. There is no certainty: (i) that the Company will succeed in its Force Majeure claim and meet the minimum RECS commitment for 2010; or (ii) that the Company will always meet the minimum requirements of the PPA, despite further drilling. In the event that the Company is unable to fulfill the requirements of the PPA on schedule, and if NVE will not agree to amend the terms of the PPA, then the Company will be in default of the PPA. As a result, the Company may be subject to energy replacement costs (if the contract price falls below market prices) and PC replacement costs and NVE may elect to terminate the PPA, which could result in a material adverse effect on the Company, including delay or indefinite postponement of operations at Blue Mountain and further exploration and development of our projects with the possible loss of such assets. Blue Mountain Risks  Uncertainty Concerning Ability to Comply with Terms of the Loan Agreement with John Hancock Under the terms of the John Hancock loan, we are subject to certain budgets, covenants and conditions. The Company is currently in compliance with these covenants, however, failure to meet these budgets, covenants and conditions due to higher operating costs, higher capital costs, lower than forecast electricity production and/or other unforeseen factors would result in an unanticipated covenant breach and/or default of the John Hancock agreement. In the event of a default, John Hancock may elect to call the loan and execute upon the security, which would result in a material adverse effect on the Company, including the possible loss of the Blue Mountain assets. 11


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12 Blue Mountain Risks  Uncertainty Concerning Ability to Comply with Terms of the Loan Agreement with the Trust Company of the West As of the second calendar quarter 2009, the Companys NGP Holdco subsidiary, the owner of the equity interest in NGP 1, was not in compliance with the terms of its loan agreement with Trust Company of the West (TCW), principally due to project costs exceeding budgeted amounts. During November 2009, the Company and TCW reached an agreement in principal that TCW would waive the non-compliance in return for 4.5 million NGP warrants exercisable at Cdn $1.50. The agreement was documented when the John Hancock loan closed, during September 2010, and as of the date of this report the Company is in compliance with the terms of both the TCW loan and the John Hancock loan. On November 12, 2009 NGP 1 received a $57.9 million grant from the US Department of Treasury and repaid $30 million of the TCW loan. NGP 1 used the majority of the remaining $27.9 million to complete further drilling at the Blue Mountain project, which facilitated production at the PPA minimum of 36.1 MW. At June 30, 2010 NGP 1 owed TCW approximately $164 million, which was paid down to approximately $86 million by September 30, 2010. NGP 1 intends to apply for a second cash grant and also, if possible, monetize some tax benefits to raise additional funds to be applied to further reduce the TCW loan. NGP 1 must further repay TCW and produce at least 40 MW to remain in compliance with TCW loan terms, particularly the debt service coverage ratio. Higher power production than the minimum nomination (in 2011, 35 MW, and declining 3% per year) will require lender approval and third party engineering reports supporting higher sustainable power production. Since November 20, 2010, the PPA with NVE precludes payment of the full contract sales price for power production higher than supply amount plus 5% (currently 36.75 MW) - meaning a waiver and/or PUC approval of production greater than 36.75 MW is required to receive the full contract sales price rather than the excess power rate. While the Company believes that NVE and its lenders will approve higher power production, failure to increase power production and/or to obtain additional lower cost funding may result in a default under the terms of the TCW loan agreement. In the event of a default TCW may elect to call the loan and execute upon the security, which would result in a material adverse effect on the Company, including the possible loss of the Holdco and NGP I equity. Risks associated with the Ormat Nevada Inc. joint venture On November 1, 2010 the Company and Ormat Nevada Inc. (Ormat), a wholly-owned subsidiary of Ormat Technologies Inc. (NYSE-ORA) announced a letter agreement under which they agreed to form Crump Geothermal Company LLC (CGC), with each party holding an initial 50% interest in CGC, and to develop, construct, own and operate one or more geothermal power plants at the Crump Geyser Project (the Crump Project) located in Lake County, Oregon. Ormat has agreed to pay $2.5 million to the Company over three years and to fund $15 million of development phase work (collectively, the Development Obligations), following which, the parties will each be responsible for funding their 50% share of costs. NGP has the option to borrow under a bridge financing facility from Ormat for all or part of NGP's share of costs up to US$15 million. Any bridge loans extended to NGP by Ormat will mature on the earlier of obtaining third party non-recourse financing or upon achieving commercial operations, with an additional 90- day extension for any portion of bridge debt to be repaid from proceeds of a Treasury Cash Grant. 12


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13 If either party to the agreement fails to make its pro-rata payment of an approved budget, the non-contributing party will be subject to customary dilution of its equity interest. If NGP is diluted, it will have an option to reinstate its 50% ownership position up to the date of commercial operation of the power plant. In no event will the NGP's ownership interest be diluted below 20%. Ormat may decide to discontinue work at the Crump Project at any time prior to satisfying the Development Obligations, as a result of which Ormats interest in CGC will revert to NGP. Management believe that dilution is the primary Crump Project risk. In the event both a construction loan and a permanent loan were unavailable on reasonable terms prior to commercial operation, the Company may suffer dilution albeit protected by a 20% minimum interest in the project. Without New Financing We May Not Be Able To Maintain Operations The Company will not receive funds, beyond a payment for services provided, from Blue Mountain until the TCW loan is paid down to a target note balance, starting at $70 million, and NGP 1 complies with covenants. In the event that the Crump Project development work demonstrates commercial feasibility, it will not result in an operating plant prior to 2013 and therefore it also will not provide funds, beyond payments for services provided, for a number of years. The Company is dependent upon its $12.5 million cash balance and potential future financing to support corporate operations and property development costs (other than $1.7 million and $1.6 million matching DOE grants for Crump and North Valley). The Company spends about $1 million per quarter on corporate operations. There is no guarantee that the funds available to the Company will be sufficient, and there is no guarantee that the Company will receive funds from any of its projects. While the Company has been successful to date in its efforts to raise financing through the sale of equity, there is no guarantee the Company will be successfully financed in the future. The Company is currently drilling additional wells to support higher power production, seeking financing for Blue Mountain, and also beginning a joint venture with Ormat, however there is no certainty that these endeavours will be successful. Rising Inflation May Reduce or Eliminate Our Potential Profitability The price escalation provisions in the Power Purchase Agreement with NVE may not keep pace with inflation thereby reducing or eliminating NGP 1 potential profitability and increasing the default risk with both John Hancock and TCW. Project price inflation may affect the return on investment at Crump but the Company is partly protected by the low level of its committed investment - $15 million to be borrowed from Ormat. Resource Risks There are numerous uncertainties inherent in estimating quantities of prospective geothermal resources (i.e. power production), including many factors beyond the Companys control. The resource information set forth herein represents estimates only. The resource from the Blue Mountain property has been independently evaluated by a third party consultant. The evaluation 13


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14 includes a number of assumptions relating to the geology as presently understood over the producing life of the resource. The assumptions were based on information available at the date the relevant evaluations were prepared, and many of these assumptions are subject to change and are beyond the Company's control. Actual production and net revenue derived therefrom will vary from these evaluations, and such results could be materially less than anticipated, which would result in a material adverse effect on the Company, including delay or indefinite postponement of operations and further exploration and development of our projects with the possible loss of such assets. General Development Risks Our development activities are inherently risky and the risks involved with the development of a geothermal resource cannot be over-stated. Our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond our control, including economic conditions, mechanical problems, title problems, weather conditions, compliance with governmental requirements and shortages or delays of equipment and services. If our drilling activities are not successful and/or over budget we may experience a material adverse effect on our future results of operations and financial condition. In addition to the risk that wells drilled will not be productive, or may decline in productivity after commencement of production, hazards such as unusual or unexpected geologic formations, pressures, mechanical failures, blowouts, cratering, explosions, uncontrollable flows of well fluids, pollution and other physical and environmental risks are inherent in geothermal exploration and production. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environment damage and suspension of operations. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential claims. We do not fully insure against all risks associated with our business either because such insurance is not available or because the cost of such coverage is considered prohibitive. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our financial condition and results of operations. Lack of Proven Reserves on Pumpernickel, Edna, North Valley (formerly Black Warrior) and Crump Properties Despite exploration and development work, our Pumpernickel, Edna, North Valley and Crump properties do not have proven geothermal energy reserves. Substantial additional work is still required in order to determine if any economic geothermal reserves are located on these properties. In the event commercial quantities of geothermal resources are discovered, the Company may be unable to bring such resources into commercial production. Finding geothermal resources is dependent on a number of factors, not the least of which is the technical skill of exploration personnel involved. The commercial viability of a geothermal resource once discovered is also dependent on a number of factors, some of which are particular attributes of the resource, such as size, and proximity to infrastructure, as well as capital costs and energy prices. Many of these factors are beyond our control. Failure of these properties to have proven geothermal reserves may have a material adverse on the Company. 14


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15 Energy price fluctuations The market price of energy is volatile, unpredictable and cannot be controlled. If the price of green electricity (meaning electricity that generates renewable energy credits) should drop significantly, the economic prospects of our projects could be significantly reduced or rendered uneconomic which could result in a material adverse effect on the Company, including delay or indefinite postponement of operations and further exploration and development of our projects with the possible loss of such assets. There is no assurance that, even if commercial quantities of geothermal resources are discovered, a profitable market will exist for the sale of same. Factors beyond our control may affect the marketability of any geothermal resources discovered. Prices have fluctuated widely, particularly in recent years. The marketability of geothermal energy is also affected by numerous other factors beyond our control, including government support, government regulations relating to royalties and taxes, as well as allowable production and exporting of energy sources, the effect of which cannot be accurately predicted. Industry Competition Significant and increasing competition exists for the limited number of geothermal opportunities available. As a result of this competition, some of which is with large established companies with substantial capabilities and greater financial and technical resources than we have, we may be unable to acquire additional geothermal projects beyond those on currently leased property on terms we consider acceptable. There can be no assurance that acquisition programs will yield new geothermal projects. Environmental and Other Regulatory Requirements Our current or future operations, including development activities and production on our properties, require permits from various governmental authorities and such operations are and will be subject to laws and regulations governing development, geothermal resources, production, exports, taxes, labour standards, occupational health, waste disposal, toxic substances, land use, environmental protection, project safety and other matters. Companies can experience increased costs, and delays in production and other schedules as a result of the need to comply with applicable laws, regulations and permits. There is no assurance that all approvals and required permits will be obtained. Additional permits and studies, which may include environmental impact studies conducted before permits can be obtained, may be necessary prior to operation of the properties in which we have interests, and there can be no assurance that we will be able to obtain or maintain all necessary permits that may be required on terms that enable operations to be conducted at economically justifiable costs. Failure to comply with applicable laws, regulations, and permitting requirements may result in enforcement actions thereunder, including orders issued by regulatory or judicial authorities causing operations to cease or be curtailed, and may include corrective measures requiring capital expenditures, installation of additional equipment, or remedial actions. We may be required to compensate those suffering loss or damage by reason of our activities, and may have civil or criminal fines or penalties imposed upon us for violations of applicable laws or regulations. Further, amendments to current laws, regulations and permits governing operations and activities of geothermal companies, or more stringent implementation thereof, could have a material 15


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16 adverse effect on the Company and cause increases in capital expenditures or production costs, or reduction in levels of production, or abandonment, or delays in development of the business. All of the above could have material adverse effects upon the Company. Risks may not be insurable While we maintain appropriate insurance for liability and property damage, we may become subject to liability for hazards that cannot be insured against or fall beyond our coverage, which if such liabilities arise, they could reduce or eliminate future profitability for our Company. Our operations involve the use of dangerous and hazardous substances. While extensive measures are taken to prevent discharges of pollutants in the ground water and the environment, and we believe that we maintain appropriate insurance for liability and property damage in connection with our business, we may become subject to liability for hazards that cannot be insured against or for which we may elect not to insure ourselves due to high premium costs or other reasons. Should such liabilities arise, they could suspend or delay our current projects, reduce or eliminate our future profitability, resulting in a decline in the value of our securities. Further, in the course of exploration, development and production, certain risks and, in particular, unexpected or unusual geological operating conditions may occur. It is not always possible to fully insure against such risks and we may decide not to take out insurance against such risks as a result of high premiums or other reasons. Should such liabilities arise, they could reduce or eliminate any future profitability and result in increasing costs and a decline in the value of our securities and a failure of our business. Title Risks Adverse claims on our title may adversely affect our business. Although we have taken reasonable precautions to ensure that legal title to our properties is properly documented, there can be no assurance of title to any of our property interests, or that such title will ultimately be secured. Our property interests may be subject to prior unregistered agreements or transfers or other land claims, and title may be affected by undetected defects and adverse laws and regulations. If such adverse claims on our title were successful this may result in the failure of our business. Third Party Risk The success of our business relies on our ability to retain others and the services and performance of third parties. We are dependent upon outside sources for engineering, procurement and construction services, the leasing or renting of crucial drilling equipment, and related equipment, essential in the conduct of our business. There can be no assurance that required equipment will be available to us when needed, that it can be purchased leased or rented economically, or that such equipment will perform satisfactorily. In addition, there exists counter party risk in our lenders, our venture with Ormat at the Crump Project, our EPC contracts, our power plant suppliers, and our bank deposits. The ability to continue our projected operations is heavily dependent on the sale of power under the PPA, the performance of our joint venture partners and the continuing support of our lenders. The failure to perform by these third parties may prevent our continued operations or cause delays in construction or operations and have other material adverse effect on our projects. 16


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17 Risks Relating to Financial Matters Limited Operating History and History of Losses Although the Company began earning revenue in August 2009, and has earned approximately $11.8 million for the year ended June 30, 2010, since incorporation the Company has recognized significant losses. It is anticipated that we will not earn sufficient revenue to cover operating expenses until we increase power production at Blue Mountain, repay more of the TCW loan and/or bring CGC into production. Except as indicated herein, we have no revenue history and there can be no assurance that our operations will be profitable in the future. Working Capital Deficiency At June 30, 2010, we had cash and equivalents in the amount of $6,435,375 and a working capital deficiency of $145,818,712. The working capital deficiency is primarily due to the classification of the TCW loan as a short term liability, which is a result of the Company not being in compliance with certain terms of the TCW loan agreement, principally those relating to project capital costs exceeding budgeted amounts. By September 30, 2010, TCW had waived the non compliance, NGP 1 had paid the TCW loan down to approximately $86 million, the loan was reclassified to long term and the Company was in compliance with loan covenants. We May Not Be Able To Meet Our Loan Covenants The Company must repay the TCW loan and produce at least 40 MW to meet certain loan covenants, particularly the debt service coverage ratio, and remain in compliance with its terms. Failure to increase power production, which requires both NVE and lender approval (see above - Blue Mountain Risks  Uncertainty Concerning Ability to Comply with Terms of the Loan Agreement with the Trust Company of the West)and/or to obtain additional lower cost funding may result in another default under the terms of the TCW loan agreement and, in the event of a default, TCW may elect to call the loan and execute upon the security, which would result in a material adverse effect on the Company, including the possible loss of the Holdco and NGP I equity. We May Not Be Able To Meet Substantial Capital Requirements We have limited financial resources and there can be no assurance that we will be able to obtain adequate financing in the future. Failure to obtain such financing may result in a material adverse effect, a delay or indefinite postponement of further exploration and development of our projects. The Blue Mountain project requires additional drilling and while $8.4 million has been reserved for it from the John Hancock loan proceeds, there is no guarantee this is sufficient. Drilling is inherently one of the riskier aspects of geothermal development. The Company is also dependent upon raising funds for ongoing operations and additional projects in the future. Although we have been successful in obtaining financing in the past there can be no assurance that we will be able to obtain adequate financing in the future or that the terms of such financing will be favourable. Failure to obtain such financing could result in a 17


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18 material adverse effect, delay or indefinite postponement of further exploration and development of our projects with the possible loss of such assets. Variations in Exchange Rates May Have a Negative Impact Upon Our Results Fluctuation in foreign currency exchange rates may negatively affect our results. Items included in the financial statements of each entity in the group are measured using the currency of the primary economic environment in which the entity operates (the functional currency). Effective October 1, 2008, the Company designated its US subsidiary as self-sustaining and changed its reporting currency to the US dollar. The change in reporting currency was made to better reflect the Companys business activities, comprising primarily the construction of the geothermal power plant in Nevada and the associated US dollar denominated financing and US dollar denominated power purchase agreement. Prior to October 1, 2008, the Company reported its annual and quarterly consolidated balance sheets and the related consolidated statements of operations and cash flows in Canadian dollars (CAD). The Company is subject to currency fluctuations. Foreign currency fluctuations are material to the extent that fluctuations between the Canadian and U.S. dollar and/or US dollar balances are material. We do not at present, nor do we plan in the future, to engage in foreign currency transactions to hedge exchange rate risks but we do convert Canadian equity funds to US dollars anticipating US expenditures. The Companys debt, anticipated Blue Mountain revenue and operating costs are and will be denominated in US dollars. Risk Relating to Personnel Dependence on Key Personnel The success of the Company is largely dependent upon the quality of its management and personnel, including in particular Brian Fairbank, Kim Niggemann, Max Walenciak and Andrew Studley. Loss of the services of such persons may have a materially adverse effect on the Company. The Company has not purchased key man insurance on any of its directors, officers or employees, and has no current plans to do so. Additionally, not all of our directors and officers have direct training or experience in geothermal energy projects. Their decisions and choices may not take into account standard engineering or managerial strategies that geothermal companies commonly use. Consequently, our operations, earnings and ultimate financial success could suffer irreparable harm. Further, our ability to continue our business, and to develop a competitive edge in the marketplace, depends, in large part, on our ability to attract and maintain qualified key management personnel. Competition for such personnel is intense, and we may not be able to attract and retain such personnel. Our growth has depended, and in the future will continue to depend, on the efforts of our key management personnel. Loss of any of these people could have a material adverse effect on us. We May Not Be Able to Maintain an Adequate Number of Skilled Workers Our continued operations require an adequate number of skilled workers such as engineers, trades people and equipment operators. There is no assurance that we will be able to maintain an adequate skilled labour force or that our labour expenses will not increase. A shortage of skilled labour may require us to curtail our planned internal growth or may require us to use less skilled 18


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19 labour which could adversely affect our ability to construct our capital projects and/or perform other work. Our Officers and Directors May Have Conflicts of Interests Certain of our directors and officers may continue to be involved in a wide range of business activities through their direct and their indirect participation in corporations, partnerships or joint ventures. Situations may arise in connection with potential acquisitions and investments where the other interests of these directors and officers may conflict with the interests of our Company. Our directors and officers with conflicts of interest will be subject to and will follow the procedures set out by the Companys code of ethics. Indemnification May Discourage or Deter Our Shareholders from Suing Our Officers And Directors Based Upon Breaches Of Their Duties To Our Company The articles of incorporation of the Company contain provisions limiting the liability of our officers and directors for certain acts, receipts, neglects or defaults of themselves and of our other officers or directors or for any other loss, damage or expense incurred by our Company which shall happen in the execution of the duties of such officers or directors, as do indemnification agreements between us and our directors. Such limitations on liability may reduce the likelihood of derivative litigation against our officers and directors and may discourage or deter our shareholders from suing our officers and directors based upon breaches of their duties to our Company, though such an action, if successful, might otherwise benefit our Company and our shareholders. Risks Related to Investing in our Shares Our Securities May Be subject to Wide Fluctuations in Price and Limited or Lack of Liquidity Trading in our common shares on the TSX Venture Exchange and the OTC Bulletin Board is limited and sometimes sporadic. At times it may be difficult for our shareholders to sell their shares or liquidate their investments. The trading activity (volume) and price of our shares on these markets has been and may continue to be subject to wide fluctuations. Trading prices of our shares may fluctuate in response to a number of factors, many of which are beyond our control. In addition, the stock market in general, and the market for geothermal energy companies in particular, has experienced extreme price and volume fluctuations that may be unrelated or disproportionate to the operating performance of such companies. These broad market and industry factors may adversely affect the market price of our shares, regardless of our operating performance. Further, in the past following periods of volatility in the market price of a company's securities, securities class-action litigation has been instituted. Such litigation, if instituted against our Company, could result in substantial costs and a diversion of management's attention and resources. Investors' Interest in the Company May Be Diluted In the event that we issue additional shares in order to raise financing through the sale of equity securities or we decide to enter into joint ventures or a business combination transaction with other entities or corporations, then an investors' ownership interest in the Company will be 19


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20 diluted and investors may suffer dilution in their net book value per share depending on the price at which such securities are sold. There are also outstanding common share purchase warrants and options at November 20, 2010 exercisable into 35,427,500 common shares which, if exercised, would represent approximately 23% of our issued and outstanding shares. If all of these rights are exercised and all shares issued, such issuance would cause a reduction in the proportionate ownership and voting power of all other shareholders. The dilution may result in a decline in the market price of our shares. Penny Stock Regulations Affect Our Stock Price, Which May Make It More Difficult For Investors To Sell Their Stock Trading of our stock may be restricted by the Commissions "Penny Stock" regulations which may limit a stockholder's ability to buy and sell our stock. The U.S. Securities and Exchange Commission (the "Commission") has adopted regulations which generally define "penny stock" to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and "accredited investors". The term "accredited investor" refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 (excluding primary residence) or annual income for the past two years, exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in, and limit the marketability of, our common shares. Passive Foreign Investment Company Risk to U.S. Investors If we were to be treated as a passive foreign investment company (PFIC) for United States federal income tax purposes for any taxable year during which a U.S. Investor (as defined below under Taxation  Material United States Federal Income Tax Consequences  Passive Foreign Investment Company) holds our common shares, such U.S. Investor could suffer adverse tax consequences with respect to such common shares. As noted in our annual report for our taxable year ended June 30, 2009, we may have been a PFIC for the taxable year ended June 30, 2009. Based on the composition of the Companys income, assets and operations, the Company believes that it will not be treated as a PFIC for the fiscal year ended June 30, 2010. However, 20


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21 because the determination of whether the Company is a PFIC for a taxable year is made after the close of the taxable year based on actual income and assets values during such taxable year, no assurances can be given that the Company will not be treated as a PFIC for the fiscal year ending June 30, 2011 or any future year. U.S. Investors should consult their tax advisors regarding the tax consequences of the Company being a PFIC for the fiscal year ended June 30, 2010 or any future year. U.S. Investors should carefully review the section entitled "Taxation  Material United States Federal Income Tax Consequences - Passive Foreign Investment Company" contained in this annual report for a more detailed description of the PFIC rules and consult their own tax experts to determine how those rules may affect their ownership of our common shares. Investors Should Not Anticipate Receiving Dividends All of our available funds will be invested to finance the growth of our business and therefore investors cannot expect and should not anticipate receiving a dividend on our common shares in the foreseeable future. ITEM 4 Information on our Company A. History and Development of NGP We were originally incorporated under the laws of the Province of British Columbia, Canada on April 13, 1995, under the name "Blue Desert Mining Inc." Since that time, we have had the following name changes: -
     On May 25, 2000, to "Canada Fluorspar Inc."-
     On February 5, 2001, to "Continental Ridge Resources Inc."-
     On May 13, 2003, to "Nevada Geothermal Power Inc."
 Our agents in Nevada are: 1) Richard W. Harris, of the firm Harris & Thompson, of 6121 Lakeside Drive, Suite 260, Reno Nevada, 89511, and 2) CSC Services of Nevada Inc., 502 East John Street, Carson City, Nevada, 89706. Our agent in Delaware is Corporation Service Company, of 2711 Centerville Road, Suite 400, Wilmington, Delaware, 19808. Our Company is currently a reporting issuer under the securities laws of the Provinces of British Columbia and Alberta, Canada. Principal Expenditures/Divestitures for the Last Three Fiscal Years 2010
     We incurred $32,754,654 capital expenditure at the Blue Mountain power plant and $417,393 in expenditures that we capitalized as Interests in Geothermal Properties in respect of our other properties. There were no material divestitures during the year.2009
     We incurred $38,310,200 in expenditures that we capitalized as Interests in Geothermal Properties, and $93,602,699 for the construction and development of the Blue Mountain power plant.  We did not sell any marketable securities (shares of Sierra Geothermal Corp. held by the Company) in the fiscal year ended June 30, 2009. 21


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22 2008
     We incurred $25,742,445 in expenditures that were capitalized as Geothermal property interests and $18,316,373 for the development and construction of geothermal properties.  We did not sell any marketable securities (shares of Sierra Geothermal Corp. held by the Company) in fiscal year ended June 30, 2008.
 Public Takeover Offers During the previous fiscal year, we have not received any public takeover offers from third parties, nor have we made any such takeover offers. B. Business Overview We are in the renewable clean geothermal energy business. We engage in the acquisition, exploration and development of geothermal resources principally in the Western United States in Nevada and Oregon. Geothermal power is generated from energy within the earth. Electricity is generated by conventional turbines, driven by hot, high pressure water (brine) and steam from underground geothermal reservoirs. Cooled geothermal brine is re-injected into the reservoir where it is reheated to be used again in a continuous cycle. The result is clean, renewable, sustainable electric power. The Company holds 100% leasehold interests in five properties: Blue Mountain, Pumpernickel North Valley and Edna, all located in Nevada, and Crump Geyser, located in Oregon. We believe that the geothermal power business offers a combination of reasonable customer, price and construction risk, as a result of public utility commitments to long term power purchase contracts and, as long as they are available, fixed price engineering, procurement and construction (EPC) agreements. Operating risk is reduced by proven technology and annual operating costs that are modest relative to capital costs. Among the major risks are: access to and the cost of capital for large investments in exploration, development and construction activities that are not completely predictable, and also the cost of development (drilling) which can vary substantially from expectations. Geothermal power plants use proven technology to produce base load power for growing utilities, particularly those located in states, such as Nevada and Oregon, with Renewable Portfolio Standards (RPS) that are requiring generation from renewable resources. The Companys view is that demand is strong and growing from both utility and private customers, and that the value of electricity and environmental credits will increase in the future. Among sources of renewable power, geothermal is particularly attractive since it provides steady base load electricity that is not   22


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23 dependent upon the weather. The energy necessary to operate a geothermal power plant is typically obtained from several wells drilled using established technology in some respects similar to that employed in the oil and gas industry. Geothermal production wells are normally located within approximately one to two miles of the power plant. The geothermal reservoir is a renewable source of energy if natural ground water sources and re-injection of extracted geothermal fluids allows replenishing the geothermal reservoir following the withdrawal of geothermal fluids, and if the well field is properly managed. Geothermal energy projects typically have high capital costs, partly as a result of the costs attributable to well field development, but tend to have significantly lower variable operating costs, principally consisting of maintenance expenditures, than fossil fuel-fired power plants.  Power plants can employ a number of technologies, principally divided into Flash systems for high temperature resources (> 400 F usually) and binary systems for more moderate temperatures (up to 400F usually). We have determined that a binary system is best suited to resource at Blue Mountain. In a "binary system," geothermal brine is extracted from the underground reservoir and flows under pump from the wellhead through a gathering system of insulated steel pipelines to a heat exchanger, where it heats a secondary working fluid that has a low boiling point. This is typically an organic fluid, such as isopentane or isobutane that is vaporized and is used to drive the turbine. The organic fluid is then condensed in a condenser that may be cooled by air or by water from a cooling tower. Nature of Companys operations Our activities have focused on the development of renewable geothermal energy projects with an emphasis on the exploration and development of geothermal power production at Blue Mountain, Nevada. Construction of the geothermal power plant was was substantially completed 23


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24 October 9, 2009. Power sales to NVE began during August 2009, when testing began, and optimization has continued since that time. Following startup the plant operated between 60% and 80% of the target capacity and drilling and well field optimization has increased power production to approximately 36 MW, about 90% of target capacity. Additional drilling is required to support the full 40 MW target power production. In addition, the Company believes that the power plant, if fluid is available, may be capable of 45 - 47 MW (net) power production and the drilling underway is intended to capitalize on this additional capacity. Following the year end the Company entered into a 50/50 Joint Venture agreement with Ormat to develop its Crump Geyser property in Oregon. Reference is made to the heading "Property, plants and equipment" under Item 4.D below for further information relating to development of Blue Mountain, Pumpernickel, North Valley and Crump Geyser geothermal energy projects. Description of the Market The geothermal energy industry in the United States experienced significant growth in the 1970s and 1980s, followed by a period of consolidation of owners and operators in the 1990s. The industry, once dominated by large oil companies and investor-owned electric utilities, now includes several independent power producers. During the 1990s, growth and development in the geothermal energy industry occurred primarily in foreign markets, with minimal growth and development in the United States. Since 2001, there has been renewed interest in geothermal energy in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to the cost of fossil fuel-based electricity generation, and more prevalent legislative and regulatory incentives, such as state renewable portfolio standards. Electricity generation from US geothermal resources is currently concentrated in California, Nevada, Hawaii and Utah, although there are opportunities for development in other states such as Alaska, Arizona, Idaho, New Mexico and Oregon where there are geothermal resources. An additional factor fueling recent growth in the renewable energy industry is global concern about the environment. Power plants that use fossil fuels generate higher levels of air pollution and their emissions have been linked to acid rain and global warming. In response to an increasing demand for green energy, many countries have adopted legislation requiring, and providing incentives for, electric utilities to sell electricity generated from renewable energy sources. Raw Materials, Suppliers and Subcontractors We will not rely on any one supplier for the raw materials used in our activities, as all of such raw materials are readily available from various sources. We are dependent on the successful performance of counterparties to our engineering, procurement and construction (EPC) contracts, particularly Ormat Nevada Inc., who have provided power plant warranties and manufacture certain parts. Seasonality Project work in Nevada, including drilling and other surface surveys can be conducted at any time of year. Winter weather is cold, but precipitation is low and snow does not accumulate 24


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25 significantly. Topography is moderate. There has been flooding in the past at our Oregon property. If it recurs, it could impede work progress. Dependence In contemplation of locating appropriate geothermal resources at Blue Mountain, we sought out and were awarded a power purchase contract. On August 18, 2006, our wholly-owned subsidiary Nevada Geothermal Power Company, entered into a long-term firm portfolio energy credit and renewable power purchase agreement (later assigned to our NGP 1 subsidiary) with NVE, an operating electric public utility. Pursuant to the terms of this agreement, we are delivering electrical energy (measured in MWh) that is generated from our power plant constructed at Blue Mountain in Humboldt County, Nevada. We have agreed that all of our energy from this phase 1 project will be dedicated exclusively to the utility for a period of twenty years commencing immediately following the commercial operation date, namely November 20, 2009. Following Commercial Operation, without a waiver, the Company is liable for a substantial penalty in the event the TCW loan were repaid with non operating funds, such as those that may become available from debt or tax assisted financings. Also, if the Company doesnt increase power production and pay down the TCW loan it cannot meet the loan agreement interest coverage covenant. TCW waived the penalty in favour of a 2% fee when the loan was partially repaid during the third calendar quarter of 2010. TCW has further agreed to a 10% penalty if, by September 2, 2011, the loan is further repaid with grant proceeds and a 15% penalty if, by March 2, 2012, repayment is funded by specified non operating funds, such as a tax assisted financing. The Company is highly dependent upon paying down the TCW debt and covering the TCW interest payments since TCW is secured by the Companys equity interest in Holdco and NGP 1. At Blue Mountain, with wells drilled to date, modelling predicts the current configuration will cool the resource, reducing power production by approximately 2.5% per year. As a result, until drilling demonstrates higher sustainable power production lenders require lower nomination (3% per year) of supply to NVE annually. Also, since November 20, 2010 the PPA with NVE precludes higher power nomination, so in addition to successful drilling and lender approval, the Company requires NVE and/or Nevada PUC approval to increase power production. The Company is highly dependent upon increasing power production as well as raising additional low costs capital with which to further repay the TCW loan and, consequently continuing strong relationships with all of NVE, TCW, John Hancock and DOE are critical. In addition, we are dependent on the services of our EPC contractors for design, engineering, procurement of materials and equipment, construction, testing and provision of training on the applicable equipment. Marketing Pursuant to the terms of the August 18, 2006, power purchase agreement, amended November 3, 2008, we agreed to provide 36.1  44.1 (net) MW of geothermal energy generated at the phase 1 power plant at Blue Mountain. Power deliveries are permitted to decline 3% per year without penalty. The power generation industry is characterized by intense competition from electric utilities, other power producers, and marketers. In recent years, the United States in particular has seen increasing competition in power sales, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term sales. While the current demand for renewable energy is strong, 25


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26 increased competition and/or fluctuations in fossil fuel consumption and prices may contribute to a reduction in electricity prices for new renewable projects. We also compete with companies engaged in the power generation business from renewable energy sources other than geothermal energy, such as wind power, solar power and hydroelectric power. Regulation of the Electric Utility Industry The following is a summary overview of the electric utility industry and applicable federal and state regulation, and should not be considered a full statement of the law or all issues pertaining thereto: PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 The Public Utility Regulatory Policies Act of 1978 (PURPA) provides certain benefits described below, if a project is a Qualifying Facility. There are two types of Qualifying Facilities: cogeneration facilities and small power production facilities. A small power production facility is a Qualifying Facility if (i) the facility does not exceed 80 megawatts; (ii) the primary energy source of the facility is biomass, waste, renewable resources, or any combination thereof, and 75% of the total energy input of the facility is from these sources; and (iii) the facility has filed with the Federal Energy Regulatory Commission (FERC) a notice of self-certification of qualifying status, or has filed with FERC an application for FERC certification of qualifying status, that has been granted. (FERC has established other requirements for cogeneration facilities; however, none of our projects are planned to be cogeneration facilities.) PURPA exempts Qualifying Facilities from regulation under the Public Utility Holding Company Act of 2005 (PUHCA 2005), state laws relating to the financial, organization and rate regulation of electric utilities and, depending on the type and size of Qualifying Facility, certain provisions of the Federal Power Act (FPA). In addition, FERCs regulations promulgated under PURPA require that electric utilities purchase electricity generated by Qualifying Facilities at a rate based on the purchasing utilitys incremental cost of purchasing or producing energy (also known as avoided cost), unless, as discussed below, FERC has determined that the Qualifying Facility is located in an area where it has access to a competitive electricity market. Qualifying Facilities must obtain market-based rate authority under Section 205 of the FPA for sales of energy or capacity from facilities larger than 20 MW in size, unless such sales are made either (i) pursuant to a contract executed on or before March 17, 2006, or (ii) made pursuant to a state regulatory authoritys implementation of section 210 of PURPA. Under regulations promulgated pursuant to provisions of the Energy Policy Act of 2005, after August 8, 2005, FERC may terminate an electric utilitys obligation to enter into new contracts for the purchase of energy from Qualifying Facilities upon a finding that Qualifying Facilities have non-discriminatory access to either (i) independently administered, auction-based day ahead and real time markets for energy and wholesale markets for long-term sales of capacity; (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords non-discriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity and energy, including long and short term sales; or (iii) 26


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27 wholesale markets for the sale of capacity and energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. Under current FERC regulations, there is a rebuttable presumption that Qualifying Facilities have non-discriminatory access to five regional markets and that FERC will, upon petition, eliminate the mandatory purchase obligation of utilities that operate within those organized markets, namely, the Midwest Independent Transmission System Operator, PJM Interconnection, L.L.C., New York Independent System Operator, ISO New England, Inc., and the Electric Reliability Council of Texas. Further, FERC regulations provide for procedures for utilities that are not members of these regional markets to file to obtain relief from the mandatory purchase obligation on a service territory-wide basis to the extent they can demonstrate access to competitive wholesale markets, as defined further in FERCs regulations, for the sale of capacity and energy; to the extent a petition to terminate the purchase obligation is granted by FERC, there are also procedures for affected Qualifying Facilities to seek reinstatement of the purchase obligation. Our operating project in Nevada does not sell power to an electric utility that has FERC authorization to terminate its Qualifying Facility purchase obligations, and none of our projects under development are planned to sell power pursuant to contracts with electric utilities that have received FERC authorization to terminate their obligation to enter into Qualifying Facility purchases. One of our projects has already self-certified as a Qualifying Facility with FERC, and we anticipate that our other projects under development will meet all of the criteria required for Qualifying Facilities under PURPA. PUBLIC UTILITY HOLDING COMPANY ACT The Public Utility Holding Company Act of 1935 was (PUHCA) repealed, effective February 8, 2006, pursuant to the Energy Policy Act of 2005. Although PUHCA was repealed, the Energy Policy Act of 2005 created PUHCA 2005. Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission. If a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC, provided that the company files an appropriate exemption form with FERC. Because our operating project is a Qualifying Facility that makes only wholesale sales of electricity (and our projects under development will also be Qualifying Facilities), we are exempt from FERCs regulation over the books and records of holding companies and, as discussed above, Qualifying Facilities already are not subject to state commissions rate, financial and organizational regulations and, therefore, generally are exempt from review of their books and records by state commissions. FEDERAL POWER ACT Pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis, if a seller can demonstrate that it does not have, or has adequately mitigated, market power in relevant markets. Qualifying Facilities are exempt from many provisions of the FPA unless, as is the case with our operating project, they are greater than 20 MW in size and do not otherwise remain exempt, as noted above, in which case they are subject to FERC rate regulation under Sections 205 and 206 of the FPA and may also be subject to other FERC regulations, including FERC authority to review mergers and 27


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28 upstream transfers of control under Section 203 of the FPA. Entities that qualify for market-based rate authorization are typically granted waivers or exemption from many provisions of FERC regulation otherwise applicable to public utilities, such as FERCs regulation of books and accounts, regulation over debt and securities issuances, and certain FERC reporting requirements. However, if any of the projects fail to qualify as a Qualifying Facility, or, if applicable, fail to qualify for market-based rate authorization and the associated waivers and exemptions that are typically granted with such authorization, such project could also become subject to the full scope of the FPA and applicable state regulations, which could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. State Regulation Qualifying Facilities that engage in wholesale sales of electricity to public utilities in Nevada, are not subject to rate, financial and organizational regulations applicable to Nevada electric utilities. We intend to sell electrical output under power purchase agreements to electric utilities (such as NVE), which are regulated by their respective state public utility commission. NVE is regulated by the Public Utilities Commission of Nevada. Permits Our power plant, drilling and exploration activities require us to comply with numerous federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals. We believe that we are in substantial compliance with such laws and regulations relating to our exploration activities. However, such laws and regulations may change in the future in a manner which will increase the burden and cost of compliance. Environmental Laws and Regulations We are subject to numerous federal, state and local statutory and regulatory environmental standards, including, without limitation, the provisions of the Clean Air Act, Safe Drinking Water Act, Endangered Species Act, Clean Water Act, Rivers and Harbours Act, National Pollutant Discharge Elimination System, Resource Conservation and Recovery Act, the Nevada Revised Statutes and Nevada Administrative Codes, Oregon Revised Statutes and Oregon Administgrave Rules, and federal regulations  and, on federal lands or when using federal funds, the National Environmental Protection Act and the National Historic Preservation Act. Geothermal operations can produce significant quantities of brine, and scale which builds up on metal surfaces in our equipment with which the brine comes into contact. These waste materials, most of which are re-injected into the geothermal reservoir, can contain various concentrations of hazardous materials, including naturally occurring arsenic, lead and radioactive materials. We also use various substances, including isobutene, isopentane, and industrial lubricants, that could become potential contaminants and are generally flammable. As a result, our projects are subject to numerous federal, state and local statutory and regulatory standards relating to the use, storage, fugitive emissions and disposal of hazardous substances. The cost of any remediation activities in connection with a spill or other release of such contaminants could be significant. 28


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29 Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of our projects, that has materially impaired any of the project sites, disposal or release of these materials onto project sites, other than into permitted injection wells, could result in material cleanup requirements or other responsive obligations under applicable environmental laws. At this time, the company does not believe that the cost of compliance at the federal, state and local levels will be significant. Incentive Programs During 2008, the United States extended the production tax credits for energy derived from a geothermal deposit (a geothermal reservoir consisting of natural heat which is stored in rocks, steam or fluid) to geothermal facilities placed in service before January 1, 2011. The production tax credit currently is 2.1 cents per kilowatt hour (which is adjusted annually for inflation) over a 10-year production tax credit period beginning on the placed-in-service date. Without an extension, the Company would have to place its qualifying geothermal facilities in service before January 1, 2011 to benefit from production tax credits. On February 17, 2009, the President of the United States signed into law the American Recovery and Reinvestment Act of 2009 (ARRA) containing several provisions favourably affecting the Companys projects. Most importantly, production tax credits (PTC) were extended through 2013, but in addition the Company has benefitted and may benefit at Crump from an option to elect a 30% investment tax credit (ITC) that is eligible for a cash grant. The ITC/cash grant provides a more immediate benefit than PTC that would be earned over the first ten years of commercial operation. During November 2009 the Company received a $57.9 million cash grant for its Blue Mountain project. C. Organizational Structure As at the date of this Annual Report, we have the following wholly-owned subsidiaries: 1. Nevada Geothermal Power Company (NGPC, Power Company), formerly Noramex Corp.) a company incorporated in the State of Nevada;
2. Blue Mountain Power Company Inc. (formerly Powertec Development Company Ltd.), a company incorporated in the Province of British Columbia, Canada; 
3. Desert Valley Gold Co., a company incorporated in the State of Nevada; 
4. NGP Chile S.A., a company incorporated in Chile;
5. NGP Blue Mountain Holdco LLC (NGP Holdco, Holdco), a limited liability company formed in the State of Delaware;
6. NGP Blue Mountain Holdco II LLC, a limited liability company formed in the State of Delaware;
7. NGP Blue Mountain Holdco III LLC, a limited liability company formed in the State of Delaware;
8. NGP Blue Mountain Holdco IV LLC, a limited liability company formed in the State of Delaware; 
9. NGP Blue Mountain I LLC, a limited liability company formed in the State of Delaware; 
10. NGP Blue Mountain II LLC, a limited liability company formed in the State of Delaware; 
11. NGP Blue Mountain III LLC, a limited liability company formed in the State of Delaware; 
12. NGP Blue Mountain IV LLC, a limited liability company formed in the State of Delaware; 29


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30 13. Nevada Geothermal Operating Company LLC, a Delaware limited liability company formed in the State of Delaware; 
14. NGP (Black Warrior I), a company incorporated in the State of Nevada; 
15. NGP (Crump I), a company incorporated in the State of Nevada; 
16. NGP (Pumpernickel I), a company incorporated in the State of Nevada; 
17. Nevada Geothermal Power Holding Company LLC, a limited liability company formed in the State of Delaware; 
18. Nevada Geothermal Power US Holdings Inc., a company incorporated in the State of Nevada. D. Property, Plants and Equipment Executive Offices We rent approximately 4,600 sq. ft. of executive and administrative office space, located at Suite 900-409 Granville Street, Vancouver, B.C., Canada V6C 1T2, for the sum of $11,139 CDN per month. Our present lease is expiring in May 2011, and we are currently negotiating a new lease. In Winnemucca, Nevada, we rent approximately 1,200 sq. ft. of office space located at 657 Anderson Street, Winnemucca, Nevada, 89445-3657, at a cost of $650 US per month. In Reno, Nevada, we also rent approximately 3,300 sq. ft. of office space located at 595 Double Eagle Court, Suite 2001, Reno, Nevada, 89521, at a cost of $3,344 US per month. Area of Interest and Interests Held The geothermal systems of Nevada and Oregon are located in the region known as the Basin and Range, an area linked to tectonic extension, rifting and high heat flow. The Earth's crust in north-western Nevada is the thinnest in the Basin and Range and is characterized by extensive deep faulting and fracturing, which allows water to circulate in the hot rock formations. All of our property interests lay in the Basin and Range. Nevada Geothermal Power Company, a subsidiary of Nevada Geothermal Power US Holdings Inc., both our indirectly held, wholly-owned subsidiaries, is the exploration manager for all of our projects. Lease rights for all our projects are held independently in separate subsidiaries of Nevada Geothermal Power US Holdings Inc. NGP Blue Mountain 1, NGP Crump 1, NGP Pumpernickel 1 and NGP Black Warrior 1 holds all lease rights relating to their respective projects. The Federal Bureau of Land Management ("BLM") is empowered to grant lease rights on federal lands. The Nevada Land and Resource Company, LLC ("NLRC") grants leases covering patented lands, while other lessors such as Burlington Northern Santa Fe ("BNSF"), JHG, LLC c/o Will DeLong ("DeLong"), The Crawford Farm ("Crawford"), Newmont USA Limited, dba Newmont Mining Corporation ("Newmont"), 1988 Stabb Living Trust ("Stabb"), LX Ranch Inc. ("LX Ranch"), O'Keeffe Ranch ("O'Keeffe Ranch") and RLF Nevada Properties, LLC ("RLF") have granted leases to us on private lands. Some leases grant surface rights, and those leases granted by NLRC and RLF also grant water rights. 30


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31 Location The accompanying map shows the locations of Nevada Geothermal Powers geothermal development projects.  BLUE MOUNTAIN PROJECT   All assets relating to the Blue Mountain project, including leases, were contributed to NGP I during 2007. The Blue Mountain property is located in north-central Nevada, about 32 km (22 miles) west of the town of Winnemucca in Humboldt County. The Company has leased the geothermal mineral interest in 17 land sections covering 4,445 hectares (10,984 acres). The Company holds a 100% geothermal mineral interest and is entitled to explore, develop, and produce any geothermal resources located on the properties. Blue Mountain is 33 km (21 miles) from the power grid servicing all of the major power consumers in northern Nevada with interconnections to California and Idaho. From Winnemucca, the property is accessible year-round via Jungo Road, a gravel road that passes to the south of Blue Mountain. At a point just west of Blue Mountain, a dirt road off Jungo Road leads north, about 5.5 km (3.5 miles) to the site. Power plant and transmission line construction are complete. Wellfield drilling to date supports 90% of the targeted 40 (net) MW power production, and is projected to decline 2.5% per year based on a report by an independent consultant. The Power plant is a state-of-the-art, near zero-emission, water-cooled, geothermal plant with >150°C (300°F) thermal water supplied by six production wells (five typically operate simultaneously) and six injection wells (four typically 31


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32 operate simultaneously). GeothermEx Inc. has modelled the wellfield reservoir and suggests additional wells, further from production wells, are required to increase sustainable power production to the target level and reduce the rate of production decline. Geothermal water is re-injected to maintain reservoir pressure and productivity. Ormat was the turn key engineering procurement and construction contractor for the binary geothermal power plant and has provided a one year warranty as well as a five year warranty on certain equipment replaced as a result of the January 2010 electrical incident. BLUE MOUNTAIN LEASES In July 2003, we acquired a 100% interest in and the shares of Blue Mountain Power Company, in a non-arms length transaction, from the shareholders of Blue Mountain Power Company, who included Brian Fairbank, Jack Milligan, and Mr. Fairbank's wholly-owned companies Tywell Management Inc. and Fairbank Engineering Ltd. As consideration for the acquisition, we issued an aggregate of 5,500,000 of our common shares, of which Mr. Fairbank received 3,932,000 shares, Mr. Milligan received 510,000 shares, and Frank Diegmann, formerly a major shareholder of NGP, received 407,000 shares. At the time of acquisition, Blue Mountain Power Company held, through its wholly-owned subsidiary Nevada Geothermal Power Company, geothermal leases covering 100% of 7,000 acres. NGPC subsequently acquired geothermal leases covering an additional 3,984.3 acres. Particulars with respect to the Blue Mountain leases are as follows: Owner
     Lease No.
     Sections
     Acreage
     Effective Date
     Expiry Date1
     BNSF
     187556
     15, 23
     1,280.00
     March 1, 1994
     February 28, 20142
     NLRC
     189093
     1, 11, 25, 27, 35
     3,333.48
     March 31, 2003
     March 30, 20133
     BLM
     N58196
     14
     663.36
     April 1, 1994
     March 31, 20444
     BLM
     N77668
     10, 12, 22, 24, 26
     3,297.94
     August 1, 2004
     July 31, 20145
     BLM
     N80086
     16
     650.32
     August 1, 2006
     July 31, 20166
     BLM
     N80159
     28
     640.00
     August 1, 2006
     July 31, 20167
     Crawford
     Private
     21
     640.00
     January 10, 2006
     January 9, 20168
     RLF
     Private
     13
     640.00
     March 31, 2003
     March 30, 2013Total
     
     
     11,145.1
 Blue Mountain water and surface access: 9
     JHG,LLC (DeLong)
     Private-Surface only
     27
     640.00
     August 27, 2009
     August 26, 2029
 32


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33 1. Lease No. 187556 with BNSF This lease was renewed for consideration of $6,400. NGP kept this lease in good standing by paying BNSF rental payments of $5.00 per acre, per year. We are committed to pay 1.5% of royalties to BNSF as the geothermal energy is produced by binary technology, This lease includes the exclusive right to use the Leased Premises for the slant drilling of wells having their surface locations upon either the Leased Premises or adjoining land and having their well bores passing through the subsurface of the leased premises. Currently, NGP is committed to pay the following royalties to BNSF:a)
     3% of the gross proceeds for geothermal energy used for electric or non-electric purposes.b)
     5% of the proceeds at point of sale from the sale of by-products or substances other than geothermal energy which are produced in paying quantities.
  2. NLRC lease No. 189093 This lease was granted for consideration of $5,117.60, representing $2.00 per acre for each acre that comprised the original lease. The lease was kept in good standing by:a)
     Paying NLRC the following rental payments per acre, per year, to begin on the first anniversary of the Effective Date of March 31, 2003:i.
     On the first through third anniversaries of the Effective Date: $2.00 per acre;ii.
     On the fourth through sixth anniversaries of the Effective Date: $6.00 per acre; andiii.
     On the seventh anniversary and each anniversary that follows: $6.00 per acre plus a 3% increase in the rental payments annually.b)
     Expending the following amounts in work commitments per lease year:i.
     Year 1: $10,000;ii.
     Year 2: $20,000;iii.
     Year 3: $50,000;iv.
     Year 4: $50,000;v.
     Year 5 and each subsequent lease year until commercial production of geothermal resources on the property: $100,000. If in any year, we do not fulfill the work commitments, we must pay NLRC the sum equal to the difference between the work commitment obligation and the actual work expenditures for the lease year. See the BLM Unit Discussion, below. NGP has purchased the surface of Section 35 in June 2008 and purchased surface rights of Sections 11 Section 25 in December 2009. NGP did not exercise the option to purchase Section 1. 33


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34 We were committed to pay the following royalties to NLRC: a.
  3.5% of the gross revenues from the availability, sale or use of electricity from an electrical power generating plant built on or utilizing geothermal resources from the property; We had the option to purchase this royalty for $1,000,000 at any time not later than 6 months following the commencement of commercial production. NGP exercised this option and purchased the royalty in 2009. 3. BLM Lease No. 58196 The lease terms and royalty provisions were elected to convert under 43 CFR 3200.7(a) (2) in October 2009 to subject the lease to the new royalty and other provisions enacted under the Energy Policy Act of 2005 and regulations there under in 2007. As a non-competitive lease beyond its 10-year primary term, the Company is required to make rental payments of $5.00 per acre in order to keep the lease in good standing. This lease is in commercial production and not subject to further work requirements. We are committed to pay BLM royalty rates of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. 4. BLM Lease No. 77668 The lease terms and royalty provisions were elected to convert under 43 CFR 3200.7(a) (2) in October 2009 to subject the lease to the new royalty and other provisions enacted under the Energy Policy Act of 2005 and regulations promulgated there under in 2007. As a non-competitive lease, during the first ten years of the primary term the Company is required to make rental payments of $1.00 per acre in order to keep the lease in good standing. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates for geothermal resources produced for commercial generation of electricity of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. 5. BLM Lease No. 80086 The lease terms and royalty provisions are elected to convert under 43 CFR 3200.8(b) (1) (2) in October 2009 to subject the lease to the new royalty and other provisions enacted under the Energy Policy Act of 2005 and regulations there under in 2007. 34


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35 As a non-competitive lease, during the first ten years of the primary term the Company is required to make rental payments of $1.00 per acre in order to keep the lease in good standing. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates for geothermal resources produced for commercial generation of electricity of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. 6. BLM Lease No. 80159 The lease terms and royalty provisions are elected to convert under 43 CFR 3200.8(b) (1) (2) in October 2009 As a non-competitive lease, during the first ten years of the primary term the Company is required to make rental payments of $1.00 per acre in order to keep the lease in good standing. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. 7. Crawford Farm Lease This lease was granted for consideration of $2,560, representing $4.00 per acre for each acre of the property. To keep this lease in good standing, we must: a)
     Pay Crawford $4.00 per acre per year beginning on the first anniversary of the Effective Date, January 10, 2006, and on each subsequent anniversary:b)
     Expend the following amounts in work commitments per lease year:i.
     Year 1: $10,000;ii.
     Year 2: $10,000;iii.
     Year 3: $20,000;iv.
     Year 4: $20,000;v.
     Year 5: $40,000. If in any year, we do not fulfill the work commitments, we must pay Crawford the sum equal to the difference between the work commitment obligation and the actual work expenditures for the lease year. 35


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36 We have the option to purchase surface rights needed for geothermal operations any time on or before the fifth anniversary of the Effective Date for $125.00 per acre. Beginning on and including the sixth anniversary of the Effective Date, this purchase price will be increased by 3% annually. This option to purchase the surface rights is subject to the royalties payable to Crawford. We are committed to pay the following royalties to Crawford:a)
     3% of the gross revenues from the availability, sale or use of electricity from an electrical power generating plant built on or utilizing geothermal resources from the property;b)
     10% of the gross proceeds from the sale or use of any geothermal resources or associated energy consumed, processed, sold, shipped or utilized for non-electric commercial purposes;c)
     10% of the gross proceeds from the sale or use of any geothermal resources produced on the property and utilized for the production of a product other than electricity.
  8. RLF Effective October 3, 2006, RLF Nevada Properties, LLC purchased Section 13 of Lease No. 189093 from the NLRC, which maintains the Companys lease agreement terms including the effective date of this lease as at March 31, 2003. a)
     Pay RLF the following rental payments per acre, per year, to begin on the first anniversary of the original Effective Date of the NLRC Lease No. 189093 (which is March 31, 2003):i.
     On the first through third anniversaries of the Effective Date: $2.00 per acre;ii.
     On the fourth through sixth anniversaries of the Effective Date: $6.00 per acre;iii.
     On the seventh anniversary and each anniversary that follows: $6.00 per acre plus a 3% increase in the rental payments each year.b)
     Expend the following amounts in work commitments per lease year:i.
     Year 1: $10,000;ii.
     Year 2: $20,000;iii.
     Year 3: $50,000;iv.
     Year 4: $50,000;v.
     Year 5 and each subsequent lease year until commercial production of geothermal resources on the property: $100,000. If in any year, we do not fulfill the work commitments, we must pay NLRC the sum equal to the difference between the work commitment obligation and the actual work expenditures for the lease year. We have the option to purchase the surface rights any time on or before the fifth anniversary of the Effective Date March 31, 2008 for $100.00 per acre. Beginning on and including the sixth anniversary of the Effective Date, this purchase price will be increased by 3% annually. This option to purchase the surface rights is subject to the royalties payable to RLF. We are committed to pay the following royalties to RLF: 36


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37 a.
     3.5% of the gross revenues from the availability, sale or use of electricity from an electrical power generating plant built on or utilizing geothermal resources from the property;b.
     10% of the gross proceeds from the sale or use of any geothermal resources or associated energy consumed, processed, sold, shipped or utilized for non-electric commercial purposes;c.
     10% of the gross proceeds from the sale or use of any geothermal resources produced on the property and utilized for the production of a product other than electricity. 9. DeLong Water and Surface Access DeLong grants NGP right of access to Section 27 to explore for groundwater; to perform work; to drill test wells; to drill water production wells; to install production facilities and construct pipelines; and to extract water from the section. NGP shall pay DeLong an annual fee, the rate of which shall vary depending upon the stage of development: -Exploration, Drilling Test & Production Wells & construction of facilities and pipelines
-$10,000 per year.
--Extraction of water from production wells -$20,000 per year. The fee shall be due on the anniversary date and the rate shall be determined by the stage of development attained by the Company during the preceding 12 month period. Unit Agreement The above leases are the subject of a federal Unit Agreement for the Development and Operation of the Blue Mountain Unit Area, bearing an Effective Date of September 8, 2006. The purpose of this Unit Agreement is to create a contiguous area which allows a cooperative plan of development or operation and to more properly conserve natural resources and prevent waste. The United States Department of the Interior approved this agreement, with the above mentioned effective date, on September 8, 2006. A Participating Area has been defined within the unit. Blue Mountain Description, History and Development The Blue Mountain property is located about 32 km (22 miles) west of the town of Winnemucca. The Company has leased the geothermal mineral interest in 17 land sections covering 4,503 hectares (11,126 acres) from the Bureau of Land Management (BLM), Burlington Northern Santa Fe (BNSF), Nevada Land and Resource Company (NLRC), Crawford and DeLong Ranch, and RLF Nevada Properties. The Company holds a 100% geothermal mineral interest and is entitled to explore, develop, and produce any geothermal resources located on the properties. Early results on the property indicated the presence of a high temperature parent reservoir, possibly as high as 250°C (480°F). Deep production and injection drilling to date has recorded a maximum temperature of 219°C (426°F) in the western portion of the developed field (well 57-15). The 13 thermal gradient holes that have been drilled display geothermal gradients in excess of 400°C/km (1,210°F/mi) on the west side of Blue Mountain. A two-meter temperature survey was 37


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38 completed in October, 2010 which provides complimentary information on the distribution of natural shallow outflow patterns and the underlying permeable fault sources. These data define a thermal anomaly covering approximately 10km2(4 mi2) in areal extent, leaving ample area for further development and expansion. Extensive geological mapping and geophysics have been conducted on the property. Gravity, ground and airborne magnetics, seismic and magnetotelluric (MT) surveys have helped identify structures used for well targeting of the production and injection wells. Additionally, a Micro Earthquake (MEQ) study has been implemented at Blue Mountain, which is collecting valuable structural information related to the injection and production faults. Ongoing review and extended analysis of the entire geological and geophysical datasets is providing refined insights on the structural and conceptual model. These findings are driving well targeting decisions and highlighting focus areas for additional exploration. To date six commercial production wells have been drilled, 26A-14, 23-14, 25-14, 14-14, 15-14 and 17-14. Flow tests indicate that each well has the potential to produce approximately 7.2  7.5 MW (net) of power. The production zone ranges from approximately 670  1433 m (2200 4700 ft), yielding initial temperatures of 189  194°C (373 - 381°F). Currently five of the production wells are on line. A pump is not set in well 15-14, and it remains on standby as an emergency back up production well. A seventh production well 44-14, is not capable of commercial production, due to limited permeability. This well is being further evaluated and tested, and will be considered for future deepening or re-drill operations. Three wells, 14-14, 15-14 and 44-14 have been re-completed with 9 5/8 slotted production liners to help reduce the risk of rock material entering the pump, and to ensure long term wellbore integrity. The remaining wells will be re-completed with liner during future well or pump maintenance operations. Eight injection wells have been drilled, six are deep; 58-15, 57-15ST1, 55-15, 58-11, 91-15 and 61-22ST2 ranging from 1410  2540 m (4625  8326 ft) and the two shallow injectors are capacious, both 58A-15 and 58B-15 intersected the shallow loss zone at approximately 427 m (1400 ft). However, based on the multi-well flow and injection testing conducted by an independent third party consultant, GeothermEx Inc., the shallow injectors do not provide pressure support to the reservoir. In December 2009, injection well 55-15 was successfully completed to a depth of 7707ft. This well has been placed in service and is considered one of the best injection wells due to the deep injection zone, which increases the reservoir sweep and residence times. Well 91-15, completed in February, 2010 was originally targeted and drilled as a production well. However after initially failing to be a commercially viable production well due to apparent limited permeability, the well was placed into injection service. Initial testing and actual usage of the well have demonstrated that 91-15 is a good injection well, with a deep injection zone, and longer fluid return times. In April, 2010 well 41-27 was completed to a depth of 8326ft. Due to limited permeability, this well has been converted to an observation well and is monitoring the southern field area for reservoir conditions and responses to injection/production. NGP is currently conducting step-out drilling to identify additional injection areas to the north and south of the production field in order to expand the area of exploitable resource, lengthen fluid residence times, and reduce the potential for thermal breakthrough and undesired reservoir temperature declines. As of December 15, 2010, drilling of injection well 86-22 is in progress. With completion of several new injection wells accomplished, a new tracer study was performed on three injection wells 91-15, 58-11 and 55-15. The results of the study provided valuable information used for reservoir management, and setting optimal production and injection rates for each well in service. 38


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39 The Project construction work including the power plant, well field piping, communication systems and transmission line were all completed by August 2009. The construction work included a turnkey, fixed price contract with Ormat as the equipment provider and EPC contractor. The EPC Contract provided for the construction of a three-unit binary plant with a guaranteed Substantial Completion Date (SCD) of December 31, 2009 (subject to adjustments under certain circumstances). On October 9 2009, Ormat declared early completion of the Project under the EPC Contract. During October 2009 through January 16, 2010, the power generation output of the plant was increased incrementally in coordination with improved well performance. On January 16, 2010, however, the plant tripped and was shut down completely because of overheating and fuming within and around the section of underground, high-voltage cabling known as the vault. A network of cables and other electrical equipment in the vault area and in the electrical control room were replaced under warranty as a result. Between January 17, 2010 and March 5, 2010, Ormat and its subcontractors expeditiously undertook re-engineering of the original cable ductwork configuration and replacemed all damaged and potentially damaged cables and equipment. Further, Ormat replaced the original underground cabling system with a combination of new and (where appropriate) higher-rated underground and above-ground cables that were physically separated to eliminate heat dissipation problems and cable overheating. A Force Majeure event was declared by the Project following the January 16, 2010 shutdown through March 5, 2010, the period. Since the plant returned to service the power plant has had an availability" of approximately 98% and has operated at a capacity factor of approximately 97%. The capacity factor reduction is due in part to production well pump failures. Pump failures have occurred on two occasions and the pumps were repaired and replaced. In November, during a planned outage, Ormat replaced other potentially damaged equipment. At the same time, NGP inspections of the heat exchangers showed that there is no major ongoing scaling. This confirmed NGP belief that scale inhibitors would not be necessary to protect the plant equipment. The plant, transmission line and gathering system have been built and tested. The Company began supplying power to NVE on August 18, 2009 and declared substantial completion on October 9, 2009. The plant is currently operating at approximately 90% of 40 MW targeted capacity and NGP I expects to be operating at 40  47 MW (net) with additional wells from successful drilling - since plant performance testing indicates power production may exceed the contracted target if sufficient fluid is available. Without successful drilling reservoir modelling indicates power production will decline about 2.5% per year as a result of reinjection of colder water and an associated reservoir temperature decline. The Company has been in compliance with the TCW loan terms since September 3, 2010. As of the second calendar quarter 2009, the Company was not in compliance with certain terms of its loan agreement with Trust Company of the West (TCW), principally due to project costs exceeding budgeted amounts. During November 2009 the Company agreed to give TCW 4.5 million warrants in exchange for a waiver. The Agreement was documented and formalized when the loan closed with John Hancock on September 3, 2010. The John Hancock loan provided funds for further drilling that the Company believes will permit an increase in power production to 40 MW  47 MW. The Company must successfully drill additional wells, increase power output and also pay down the TCW loan balance to continue to comply with covenants, particularly the TCW debt service coverage ratio. 39


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40 The Company declared Commercial Operation under the PPA with NVE on November 20, 2009. After declaring commercial operation under the PPA, in certain circumstances, particularly if the minimum power production is unavailable, then the Company will be liable for the cost of alternative power and portfolio credits (renewable energy credits) for a maximum of three years, after which, if the minimum power is not delivered, NVE could terminate the PPA. In the short term, the Company believes penalties will not be material, but the Company is unable to predict the penalty that may be incurred over a three year period if the current drilling program is unsuccessful. The PPA minimum power nomination was/is 36.1 (net) MW for 2010, declining 3% per year. The Company has nominated 3% less (35 (net) MW) for 2011. The PPA permitted higher power nomination until November 20, 2010, after which an NVE waiver and/or PUC approval is required. The Company is highly dependent upon successfully drilling wells to support an increase in power supply and agreement by NVE to permit it. In addition, if drilling is successful and NVE approval is forthcoming the Company must gain John Hancock approval to supply the additional power by providing a third party engineering report demonstrating higher sustainable production. In the event that the Company is unable to raise additional financing and/or increase power production then the Company could default on its obligations to TCW and/or NVE, which may have a material adverse effect on the Company, as more fully discussed in Risks relating to our Business above. Capital spending on the Blue Mountain project amounted to $32,754,654 during the 2010 fiscal year, including capitalized interest. Power Purchase Agreement(s) On June 17, 2005, the Company submitted a power bid, based on a plan to generate up to 35 (gross) megawatts electricity, to NVE in response to a request for proposal issued on May 4, 2005. On August 18, 2006, we were awarded a 20 year power purchase agreement by NVE to provide up to 35 (gross) megawatts of geothermal power from a new geothermal power plant. Approval of the agreement was received in February 2007 from the Public Utilities Commission of Nevada and Federal Energy Regulatory Commission (FERC) approval was also received in early 2007. A FERC application for a Small Power Plant Generator was made in August, 2007, using the self certifying exemption process. Under the terms of the agreement, we provided NVE with a $645,000 security deposit in the form of a letter of credit, backed by a cash deposit. On November 3, 2008, the Company and NVE amended the power purchase agreement to improve pricing and to increase power sales, consistent with the size of the resource as reported by a third party consultant. An additional cash collateralized letter of credit was provided as security to NVE in the amount of approximately $1.6 million. Further security of approximately $1.6 million was required as Operating Security when the plant began commercial operation. Our subsidiary, NGP 1, plans to submit bids for future phases of the Blue Mountain project which may involve drilling new wells to determine the field production capacity. Next steps involve drilling three additional wells to support the recently completed power plant and expand power production to 40 - 47 (net) MW. 40


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41 Permitting The following is a summary of the most important permits that were required for the Blue Mountain project: 1.
     A transmission line right-of-way application was submitted to the BLM September 29, 2006. The application was approved January 18, 2008.2.
     A request for a UEPA permit was submitted in November, 2006, to the Public Utilities Commission of Nevada ("PUCN"). A full application has been submitted to the PUCN following approval of the transmission line right-of-way environmental assessment and preliminary engineering design. PUCN granted final approval to the UEPA December 26, 2008.3.
     Application to the Bureau of Water Pollution Control for an Underground Injection Control Permit was made in December, 2006. The permit was issued March 20, 2008. Subsequent approvals to add injection wells have been approved June 25, 2009 and October 12, 2009.4.
     The request for a Class II Air Quality Permit was submitted to Nevada Department of Environmental Protection on August 4, 2008, and was approved on October 16, 2008. The permit was approved October 16, 2008. An additional approval to increase the hours of operation for generators located within the power plant was granted June 17, 2009.5.
     Following completion of facilities engineering, an application for a Chemical Accident Prevention Program Permit was submitted to the Bureau of Air Pollution Control. The permit was issued November 12, 2008.6.
     Following completion of facilities engineering, applications for County Special Use Permits were made to Humboldt and Pershing Counties. The permits were issued March 27, 2008, and May 29, 2008 respectively. On October 21, 2009, the NGP was issued a Commercial Use Permit, by the Bureau of Land Management, as is required in Federal Units.This permit is to identify methods of measurement which becomes one of the bases for royalty payment to the Department of Interiors Office of Natural Resources Revenue (ONRR (previously the Minerals Management Service).7.
     A Participating Area (N-82457-01) was approved by the US Bureau of Land Management effective August 12, 2009. The Participating Area (PA) boundary encompasses production and injection wells, power plant facilities, and other facilities necessary to support unit power generation operations, such as cooling tower water wells. The PA identifies the acreage within the Federal Unit participating in royalties. PUMPERNICKEL PROJECT Nevada Geothermal Power Co. has private and federal geothermal leases comprising a total holding of 2,810 hectares (6,942 acres). A 19 km (12 mile) transmission line would connect the property to the 120kV line at the Golconda substation to the north. The leases include 1,275 hectares (3,151 acres) of land leased under an agreement with Newmont USA Ltd, 1,405 hectares (3,471 acres) leased from BLM, 1,045 hectares (2,582 acres) acquired from Ormat for $15,000 41


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42 and a right of first offer to supply Pumpernickel power plant equipment, and 129 hectares (320 acres) under four private leases. Location Our Pumpernickel property is located in north-central Nevada, approximately 30 km (18 mi) east of Winnemucca, in Humboldt County. The property is accessible year round traveling from Winnemucca via Interstate Highway I-80, 24 km east to Golconda. Due south of Golconda (19 km), a well-maintained county gravel road leads into Pumpernickel Valley and the project area. Variable and unimproved loose surface tracks provide further access to the western portion of the property. Transmission grid access is 19 km (12 mi) from the Kramer Hill Substation on a 120 kV transmission line, and 14 km (9 mi) from a 690 kV transmission line of the northern NVE grid, or 24 km (15 mi) over flat land to the Lone Tree Mine operated by Newmont. PUMPERNICKEL LEASES The Company acquired the Pumpernickel leases beginning in February, 2004. They are listed below: Owner
     Lease No.
     Sections
     Acreage
     Effective Date
     Expiry Date1
     Newmont
     29-462-0003
     3, 5, 9, 27, 33
     3,150.85
     February 13, 2004
     February 12, 20142
     BLM
     78124
     10, 28, 34
     1,898.06
     June 1, 2006
     May 31, 20163
     BLM
     80070
     32
     640.00
     August 1, 2006
     July 31, 20164
     BLM (Ormat/Ehni)
     74855
     N 1⁄2 4, 8
     933.50
     October 1, 2002
     September 30, 20125
     Hot Springs Ranch
(Johnson, Hill, Danner, Bear)
     
     S 1⁄2 4
     320.00
     October 15, 2008
     October 15, 2018TOTAL
     
     
     6,942.41
 1. Newmont Mining Corporation Lease No. 29-462-0003 To keep this lease in good standing, we must: a)
     Pay Newmont the following rental payments, per acre (full or fraction), per year:i.
     Lease years 1 and 2: $2.00;ii.
     Year 3 and every year after: $3.00, however rentals paid to the Lessor under this subsection shall apply toward or be credited to royalties payable on actual production (if any) for the year such rentals are paid.  We are committed to pay Newmont the following royalties:a)
     3.5% of the gross proceeds of the sale of electric power, less taxes and transportation costs; 42


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43 b)
     5% of the gross proceeds of the sale of geothermal substances in arms length transactions, less taxes and transmission costs;c)
     2% of the gross proceeds of the sale of any by-products, less taxes and transportation costs;d)
     10% of the net profits produced from the use of geothermal substances at a commercial facility other than an electric power plant. Substances or electric power used by Power Company for the operations on-site are not subject to royalties. 2. BLM Lease N78124 The lease terms and royalty provisions are elected to convert under 43 CFR 3200.8(b) (1) (2) in October 2009 to subject the lease to the new royalty and other provisions enacted under the Energy Policy Act of 2005 and regulations thereunder in 2007. As a non-competitive lease, during the first ten years of the primary term the Company is required to make rental payments of $1.00 per acre in order to keep the lease in good standing. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates for geothermal resources produced for commercial generation of electricity of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. 3. BLM Lease N80070 The lease terms and royalty provisions are elected to convert under 43 CFR 3200.8(b) (1) (2)October 2009 to subject the lease to the new royalty and other provisions enacted under the Energy Policy Act of 2005 and regulations thereunder in 2007. As a non-competitive lease, during the first ten years of the primary term the Company is required to make rental payments of $1.00 per acre in order to keep the lease in good standing. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates for geothermal resources produced for commercial generation of electricity of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. 43


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44 4. BLM (Ormat/Ehni) N74855 The lease terms and royalty provisions are elected to convert under 43 CFR 3200.7(a) (2) in October 2009 to subject the lease to the new royalty and other provisions enacted under the Energy Policy Act of 2005 and regulations thereunder in 2007. We acquired this lease from Ormat for a one-time purchase price of $15,000 and a commitment to use Ormats equipment at the Pumpernickel site. Pursuant to a royalty Agreement dated April 26, 2006 between Power Company, Ormat and Ehni Enterprises, Inc., we are required to pay Ehni: a) $10,000 within ten business days of entering into a power purchase agreement with respect to this lease; and
b) A royalty of 0.5% of the gross proceeds received from the sale of electrical power, less taxes and transportation costs. We have the option to purchase the royalty from Ehni for the sum of $200,000, payable in stages up to the commencement of commercial production under a power purchase agreement in accordance with the following schedule: (a) US$50,000 upon approval of the Public Utilities Commission of Nevada ("PUCN") of a PPA for the Lease or Unit; (b) a further US$50,000 upon issuance of a UEPA Permit to construct the project by the PUCN; and
  (c) a further US$100,000 when the project begins commercial power production under the PPA. As a non-competitive lease, during the first ten years of the primary term the Company is required to make rental payments of $1.00 per acre in order to keep the lease in good standing. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates for geothermal resources produced for commercial generation of electricity of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. 5. Hot Springs Ranch (Johnson, Hill, Danner, Bear) This lease was entered between four groups of lessorsRebecca Ann Hill (one-sixth interest), Roger and Nancy Johnson (one-third interest), Ruth Ann Danner (one-sixth interest), and Allie Tipton Bear (one-third interest), and Nevada Geothermal Power Company (the Company). The four groups of lessors together own the 320 acres of land. To keep these leases in good standing, the Company is required to make annual rental payments in advance on the anniversary, in proportion to the interest of each group of lessors, during the term of the lease: 44


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45 Year
     1/3 Interest
     1/6 Interest
     100% Interest1
     $3,420
     $1,710
     $10,2602
     $4,020
     $2,010
     $12,0603
     $4,620
     $2,310
     $13,8604
     $5,220
     $2,610
     $15,6605
     $5,820
     $2,910
     $17,4606
     $12,420
     $6,210
     $37,2607
     $13,020
     $6,510
     $39,0608
     $13,620
     $6,810
     $40,8609
     $14,220
     $7,110
     $42,66010
     $14,820
     $7,410
     $44,460
  Rental payments shall apply toward or be credited to royalties payable or to become payable on actual production (if any) only for the year such rentals are paid. Annual Fee (Access Fee) will be paid to Roger and Nancy Johnson on Section 5, and Section 4 South half depending upon the type of work being conducted: Geothermal Exploration: $2,000/year;Drilling Production Wells: $4,000/year;Plant and Pipeline Construction: $8,000/year; We are committed to pay the following royalties to each group of lessors: a)
     Royalty is paid equal to either one-third or one-sixth of the rate set out below to each group of lessors:
  Royalty Rate
     Price per kilowatt hour3.5%
     Less than or equal to $0.0864%
     Greater than $0.086 to less than or equal to $0.1215%
     Greater than $0.121
  b)
     Royalty is paid equal to either one-thirdor one-sixthof five percent (5%) of the gross proceeds (which exclude deduction of royalties of any kind) from the sale of any Substances by the Company, less taxes and transportation cost;c)
     A gross royalty equal to either one-thirdor one-sixthof two percent (2%) of the proceeds from the sale by the Company of said by-products, less taxes and transportation cost;d)
     Royalty equal to either one-thirdor one-sixthof ten percent (10%) of the net profits produced by using the Substances at a commercial facility. In addition to the above royalties to each group of lessors, Roger and Nancy Johnson also granted to NGP the right to lease 200 acres of Section 1 and Section 4 South half (the Lands), excluding land (approximately 18 acres) that lies within a 500 foot radius of the Lessor's residence, as may be required for any permanent facilities necessary for power development, such as production well sites, pipeline rights of way and power plants. NGP may exercise this right to lease by giving Roger and Nancy Johnson written notice advising which portions of the Lands NGP wishes to lease (the "Surface Lease"). In consideration for the exercise of the right to the Surface Lease, NGP will pay a royalty (the "Royalty") equal to 0.29 % of the gross proceeds received from the sale of power generated from substances produced from the Unit by a power plant, payable on a monthly basis. The Royalty shall be the sole compensation due under 45


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46 the Surface Lease, and Royalty payments shall suspend any obligation to pay Access Fees provided that such Royalty payments due under any surface lease are greater than or equal to the Access Fees then due under this Agreement. If Royalty payments are not equal to or greater than the Access Fees then due, then the Access Fees shall not be suspended but may be reduced by the amount of Royalty payments paid to you. Pumpernickel Description, History and Development Surface manifestations of an underlying geothermal system in Pumpernickel Valley include a series of active geothermal springs and relic alteration minerals precipitated from extinct springs, along the western edge of the valley, apparently associated with the Pumpernickel fault. Pumpernickel Valley area is within the Humboldt Structural zone which hosts other reported major geothermal fields, including Bradys Hot Springs, Steamboat, Soda Lake, Dixie Valley, and Beowawe. Previous work on the property dates back to 1974 when Magma Power Company drilled a 920 meter (3,071 ft) hole offsetting the hot springs about 150 metres (492 ft). The temperature on the bottom was reported to have been 135°C (275°F) with the last 90 meters (300 ft) having a thermal gradient of 160°C/km. The University of Nevada System (UNS), under contract to the U.S. Department of Energy, completed an aerial assessment at Pumpernickel Valley in 19811982. UNS field work included geologic reconnaissance, satellite imagery, hot spring geochemistry, air photo analysis, a 2 metre depth temperature probe survey, gravity survey, soil mercury survey, 35 metre (115 ft) temperature gradient drilling, and additional shallow 65 -148 meter (213 - 485 ft) temperature gradient drilling. UNS work demonstrated that the geothermal fluids are likely channeled to the surface via range bounding faults, such as the Pumpernickel fault. Previous mineral exploration drill holes recorded thermal gradients of up to 283°C/km. Water samples collected from the thermal gradient drill holes and geothermal springs were sent for third party analysis and the geothermometry indicated commercial reservoir temperatures. The maximum temperature recorded from an active spring was 88°C (191°F). Geothermal water samples obtained from drilling and hot springs, analyzed by Thermochem Labs, indicate a maximum geothermometry of 220°C (428°F). Current drilling targets are expected to be in the 170°C (338°F) range. Seven thermal gradient wells were completed between 2005 and 2008. Several of these wells revealed temperature gradients higher than 100°C/km outlining a strong thermal anomaly over 2.6 km2 (1 mi2). In 2005, Premier Geophysics completed an E-SCAN resistivity survey to 3-dimensionally map Pumpernickel Valley, and the geothermal waters. The E-SCAN identifies a conductive anomaly, covering an area of about 7.8 km2 (3 mi2), with probable fluid up-flow zones. This was followed by a ground magnetic survey which was used to aid in mapping the structures. In 2006, Quantec Consulting completed a gravity survey mapping the topography of subsurface bedrock, outlining faults, and evaluating the thickness of the overburden. The survey successfully defined the Pumpernickel fault contact between the valley fill and the basement rocks, and most importantly it established the positions of valley faults with additional parallel and sub-parallel faults and their relationship to the geothermal system. The gravity data showed a good correlation with the 2005 3-D resistivity and drilling data. A seismic survey, completed at the end of 2007, was analyzed in conjunction with the prior data and it highlighted target drilling areas. 46


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47 In the fall of 2009 NGP acquired high resolution, low sun-angle photography of the property on which a photo-lineament analysis was performed. This mapping technique allows identification of subtle fault and shoreline features accentuated by the low sun shadowing effects, which are not normally recognizable from lower resolution digital elevation models (DEM) or high altitude/satellite imagery. This work led to a refined understanding of the Pumpernickel Valley Fault Zone and the inherent distribution of the underlying geothermal system. Drilling corroborates earlier studies indicating geothermal fluids are being channeled to the surface through range-front faults, and suggests that the site is an excellent prospect for a geothermal resource capable of generating electricity. The resistivity, seismic, gravity and magnetometer surveys have been completed over all the leased land to define specific drill targets. Permits are approved for two full size 13 production wells and one 7 well on private land located on the south half of Section 4 in the heart of the resource. These wells are identified as 68-4, 64-4, and 45-4. Four groundwater exploration boreholes identified a low total dissolved solids (TDS) freshwater source suitable for use in cooling towers, and for exploration drilling support. Applications were made for these four permanent water well locations. Water rights to utilize up to 2500 Acre Feet of groundwater, or enough to supply cooling tower water for a 50 MW plant were granted by the State Engineer from the Nevada Department of Water Resources Oct 21, 2010. Additionally, the site is located in an area of reasonably well-developed infrastructure with no apparent environmental issues. A Phase I Transmission Interconnection Study is complete and a follow on Facilities Study is in planning. Discussions for PPAs have been initiated with NVE and other power utilities. A total of $197,140 was expended on our Pumpernickel project during the 2010 fiscal year. NORTH VALLEY (FORMERLY BLACK WARRIOR) The Company has a total of 2,539 hectares (6,273 acres) of both private land and federal lands including water and surface rights. The private leases are subject to a 3.5% royalty on gross revenue from electricity sales, and the Company has an option to purchase the royalty interest for $1 million. Location Our North Valley property is located in Washoe and Churchill Counties, Nevada. Access to the property via a loose surface road, 447, is from Fernley, located only 30km south of the property. An alternative is Interstate Highway I-80 from Fernley to Brady's Hot Springs, then 28 km NW on loose surface road to Nightingale Mine area, and south along the road that follows the power line. NORTH VALLEY LEASES North Valley leases, which include surface and, on the NLRC leases,water rights, are as follows: Owner
     LeaseNo.
     Sections
     Location
     Acreage
     EffectiveDate
     ExpiryDate1
     NLRC
     189099
     T23N, R24E:1, 3, 5, 7,
     Washoe Co. and Churchill
     5,066.69
     August 1, 2004
     July 31, 2014
  47


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48 11, T2N, R24E: 29, 31, 35
  Co.2
     BLM
     79745
     8
     Churchill Co.
     640.00
     March 1, 2006
     February 29, 20163
     BLM
     78777
     30
     Churchill Co.
     566.40
     March 1, 2006
     February 29, 2016TOTAL
     
     
     
     6,273.09
  1. NLRC Lease No. 189099 This lease was granted for consideration of $8,853.38, representing $2.00 per acre for each acre that comprised the original lease. To keep the lease in good standing, we must: a)
     Pay NLRC the following rental payments per acre, per year, to begin on the first anniversary of the Effective Date:i.
     On the first through third anniversaries of the Effective Date: $2.00 per acre;ii.
     On the fourth through sixth anniversaries of the Effective Date: $6.00 per acre;iii.
     On the seventh anniversary and each anniversary that follows: $6.00 per acre plus a 3% increase in the rental payments each year.b)
     Expend the following amounts in work commitments per lease year:i.
     Year 1: $10,000ii.
     Year 2: $20,000iii.
     Year 3: $50,000iv.
     Year 4: $50,000v.
     Year 5 and each subsequent lease year until commercial production of geothermal resources on the property: $100,000 If in any year, we do not fulfill the work commitments, we must pay NLRC the sum equal to the difference between the work commitment obligation and the actual work expenditures for the lease year. We are committed to pay the following royalties to NLRC:a)
     3.5% of the gross revenues from the availability, sale or use of electricity from an electrical power generating plant built on or utilizing geothermal resources from the property. For greater certainty, in the event that other lands are pooled or unitized with all or any portion of the property, then the royalty rate for electrical production attributable to the property shall remain unchanged at 3.5%, and shall not be blended or otherwise affected by the royalty rates applicable to other lands than are pooled or unitized with the propertyb)
     10% of the gross proceeds from the sale or use of any geothermal resources or associated energy consumed, processed, sold, shipped or utilized for non-electric commercial purposes;c)
     10% of the gross proceeds from the sale or use of any geothermal resources produced on the property and utilized for the production of a product other than electricity. 48


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49 We have the option to purchase this royalty for $1,000,000 at any time not later than 6 months following the commencement of commercial production. 2. BLM Leases N79745 & N78777 The lease terms and royalty provisions are elected to convert under 43 CFR 3200.8(b) (1) (2) in October 2009 to subject the lease to the new royalty and other provisions enacted under the Energy Policy Act of 2005 and regulations thereunder in 2007. As a non-competitive lease, during the first ten years of the primary term the Company is required to make rental payments of $1.00 per acre in order to keep the lease in good standing. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates for geothermal resources produced for commercial generation of electricity of 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. North Valley Description, History and Development This project is located within a prolific power producing region of Nevada encompassing the Steamboat Hills, Soda Lake, Stillwater, Desert Peak, Saltwells, and Brady Hot springs geothermal power plants. Four separate power lines cross the region with convenient interconnections to the power transmission grid at Marble Bluff Substation, 16 km (10mi) west, or 19 km (12 mi) south east of the Brady's Geothermal Power Plant Substation. At North Valley, the potential for a geothermal reservoir suitable for electric power generation was indicated throughout the leased area by temperature gradients greater than 200°C/km in ten widely spaced holes drilled by Phillips Petroleum in the early 1980's. The deepest test hole (NV-ST-1) recorded a temperature of 128°C (262°F) at its maximum depth of 552 meters (1,810 feet) with temperatures still increasing at the bottom of the hole. Thus commercial resource temperatures may occur within 1,000 meters (3,000 feet) of the surface. The geology and fault structures appear to permit deep circulating ground water to be heated by anomalously high rock formation temperatures. During the summer of 2005, NGP conducted field investigations including preliminary work to prepare the site for a full Schlumberger resistivity survey. The investigations included limited testing of the Schlumberger survey at a few points. A gravity survey was conducted July 14, 2007, through July 25, 2007. Field reconnaissance and data reviews between April and August, 2008, resulted in a refined thermal anomaly contour map, that helped identify the target location for an exploration well designed to assess deep resource temperatures, fluid characteristics and geothermometry. As of August, 2008, a well pad has been graded and minor improvements to a short section of road have been completed. Future plans include further improvements to access roads and investigation of additional surface exploration methods, including geophysical procedures, a study to assess very shallow ground temperature distributions and further geological mapping. 49


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50 In May 2009 a Schlumberger (resistivity) geophysical survey was conducted on the property by Premier Geophysics. Preliminary results indicate that the ground underlying the entire survey area is moderately to highly conductive indicating the potential for a large geothermal system. Further work is necessary to determine the cause of the electrical conductance anomaly. . In October 2009 NGP received a commitment of up to $1,597,847 in shared funding (50/50 with the Company) from the US Department of Energy under the American Reinvestment and Recovery Act Geothermal Technologies Program. NGP proposes to test a simple and cost effective geological technique to locate hidden geothermal reservoirs. A total of $50,463 was expended on our North Valley project during the 2010 fiscal year, after the application of DOE funding of $17,269. CRUMP GEYSER The Company leases, at Crump Geyser, total 2,916 hectares (7,205 acres) of private land. The private leases are subject to a 3.5% royalty of gross revenues from the sale or use of electricity. Location Our Crump Geyser property is a hot spring system located in Warner Valley, Lake County, north of Adel, Oregon, 53 km (33 mi) east of Lakeview Oregon, and 287 km (178 mi) north and west from Winnemucca, Nevada. Access to the property is via Highway 140. A power line connection to the regional power grid and a transformer substation, both owned by Surprise Valley Electrification Corporation, are located approximately 0.35km (0.2 mi) to the west on Highway 140 at Adel. CRUMP GEYSER LEASES The three leases (LX Ranch, OKeeffe Ranch, Stabb Trust) were assigned by NGP (Crump 1) to Crump Geothermal Company LLC as of 30 November 2010 as part of the Ormat agreement. The LX Ranch lease was granted for consideration of $10,000, representing $2.00 per acre for each acre that comprises the lease. OKeeffe lease was granted for consideration of $1,467.52, representing $2.00 per acre for each acre that comprises the lease. Stabb lease was granted for consideration of $2,943.68, representing $2.00 per acre for each acre that comprises the lease. The initial term shall commence on the Effective Date and shall expire ten (10) years after the Effective Date, unless the Agreement is sooner terminated, cancelled or extended. Landowner grants to NGP the option to extend the term in each of the following circumstances: a)
     for two (2) additional extension terms of five (5) years each on the express condition that Lessee is actively conducting exploration and development activities on the Property at the expiration of the term immediately preceding the proposed extension term) for an unlimited number of additional extension terms of ten (10) years each on the express conditions that Geothermal Resources, or any of them, are being produced in commercial quantities in, on or from any portion of the Property or any lands that have been unitized or pooled with the Property; provided, however, that such production shall be deemed to be continuously occurring so long as such production does not cease in its entirety for more than twelve (12) consecutive months 50


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51 To keep all the leases in good standing we must: a)
     Pay LX Ranch, OKeeffe Ranch and Stabb Trust the following rental payments per acre, per year, to begin on the first anniversary of the Effective Date: i.
     First anniversary: $2.06;ii.
     Second anniversary: $2.12;iii.
     Third anniversary: $2.18;iv.
     Fourth anniversary: $4.00;v.
     Fifth anniversary: $4.12;vi.
     Sixth anniversary: $4.24;vii.
     Seventh anniversary: $4.37;viii.
     Eighth anniversary: $4.50;ix.
     Ninth anniversary: $4.64;x.
     Tenth anniversary: $4.78. If the term of the Agreement is extended pursuant to the section above, then the rental payments shall be $4.92 per acre commencing on the eleventh (11th) anniversary and shall increase at a rate of 3% per year on each subsequent anniversary until expiration or earlier termination of the Agreement. b)
     Expend the following amounts in work commitments per lease year: i.
     Year 1: $10,000;ii.
     Year 2: $20,000;iii.
     Year 3: $30,000;iv.
     Year 4: $40,000;v.
     Year 5 and each subsequent lease year until commercial production of geothermal resources on the property: $50,000. If in any year, we do not fulfill the work commitments, we must pay LX Ranch, OKeeffe Ranch, and Stabb Trust the sum equal to the difference between the work commitment obligation and the actual work expenditures for the lease year. We are committed to pay the following royalties to LX Ranch, OKeefe Ranch and Stabb Trust: a)
     3.5% of the gross revenues from the availability, sale or use of electricity from an electrical power generating plant built on or utilizing geothermal resources from the property;b)
     10% of the gross proceeds from the sale or use of any geothermal resources or associated energy consumed, processed, sold, shipped or utilized for non-electric commercial purposes;c)
     10% of the gross proceeds from the sale or use of any geothermal resources produced on the property and utilized for the production of a product other than electricity. Provided we have established a binary power plant utilizing hot water and/or steam at temperatures less than 179°C (355°F), we have the option to purchase 1% of this royalty for $500,000 at any time not later than 36 months following the commencement of commercial production. 51


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52 If LX Ranch, OKeefe Ranch and Stabb Trust are receiving production royalties, LX Ranch, OKeeffe Ranch, Stabb Trust grant us the right to lease that portion of the surface of the property as is required for production and/or transmission facilities at a surface lease rate of: a)
     $600 per acre, per year for productive crop land;b)
     $300 per acre, per year for pasture land; andc)
     $150 per acre, per year for hillside or otherwise non-productive land. Crump Description, History and Development Numerous springs, seepages and warm water marshes are present throughout Warner Valley. The two primary zones of interest are Crump Geyser and Fisher Hot Springs. The Crump Geyser hot springs occur over four miles along the western edge of Warner Valley and extend about 3,000 feet east into the valley. Crump Geyser was formed in 1959 when a 512 meter (1,680 feet) well drilled by Magma Power Company spontaneously erupted a few days after it was abandoned. The well flowed 30 litres/second (500 gallons/minute) of boiling water 45 meters (150 feet) into the air continuously for 6 months before reverting to a geyser erupting at regular intervals. During the 1960s the well was plugged with rocks to stem the geyser flow, and boiling water still rumbles at depth and bubbles to the surface. In the main geothermal zone, which includes Crump Geyser, geothermal springs are abundant as is an extensive series of northwest-southeast trending elongate mounds of siliceous/calcareous tufa. The zone appears to be structurally controlled and located along and immediately east of the prominent western scarp of Warner Valley. Waters from many springs in-and-around Warner Valley have been sampled for geochemistry by the USGS. In 1975, a series of geophysical studies conducted by the USGS, including magnetic, gravity and resistivity surveys, assessed the geothermal potential of Warner Valley. Thermal data collected from 13 heat-flow holes were reported by the USGS in 2005. In November, 2005 a series of geothermal springs were sampled and sent to Thermochem for analysis to confirm the results of the previous USGS study. The geothermometers calculated from the geochemistry suggested a reservoir source temperature of around 150°C +/- 10°C (302°F +/- 50°F). In November, 2005 Northwest Wildlife Consultants completed a preliminary wildlife survey of the Crump Geyser project area, determining that there are no endangered species that would prohibit development. From November, 2005 until the end of 2007, NGP conducted geophysical field studies and developed plans for drilling, including electrical resistivity, Schlumberger and ground magnetic surveys. The geophysical work mapped subsurface structures and indicated an excellent target indicative of geothermal fluids. Results suggest that the hot springs are associated with structurally permeable zones due to extensional faulting. An independent review by a third party consulting firm estimates that the potential capacity of the Crump Geyser reservoir is a minimum of 40 megawatt (90% probability) for 20 years, and most likely 60 megawatt for 20 years. This capacity estimate is based on a volumetric estimate of heat in place which assumes an area of 5.4 to 16 km2(most likely 10.7 km2), a reservoir 52


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53 thickness of 760 to 1,680 m (most-likely 1,070 m), and average reservoir temperature 140 to 160°C (most-likely 150°C). During May through August, 2008 a review of geochemical and thermal data, new structural mapping, and field reconnaissance identified the following targets for subsurface exploration: 1) shallow push-core holes, 2) shallow thermal gradient wells, and 3) several intermediate depth exploratory wells. In August, 2008, a third party consultant completed a comprehensive report covering permitting issues pertaining to leases, exploration, and power plant development in Oregon. In 2009 and early 2010, well designs and drilling programs were prepared and then drilling permit applications for thermal gradient wells, slim-holes, and production sized test holes were submitted to the Oregon Department of Geology and Mineral Industries (DOGAMI) In October 2009, NGP received a commitment of up to $1,764,272 in shared funding (50/50 with the Company) from the US Department of Energy under the American Reinvestment and Recovery Act Geothermal Technologies Program. The proposal will test a low environmental impact drilling technique on 8 thermal gradient and two slim-holes, as well as test methods to model the movement of fluids in the reservoir. Phase I geophysical surveys began in August 2009 (pre-dating award receipt) and were completed in October, 2010. The work included precision gravity survey, atv-towed and boat magnetic surveys, ultralight airborne magnetic survey, and a gas-piston shallow seismic reflection survey. As of November, 2010 processing of the gravity and seismic reflection data was still in progress. These data have provided an unprecedented suite of geophysical data over a geothermal prospect and will greatly aid development of the project. DOGAMI approval of the thermal gradient holes was received in May, 2010 and approval of the slim-holes and two additional production holes is pending. Completion of an archaeology survey, and wetland/upland delineation surveys is expected to lead to NEPA approval for commencing drilling activities in upland locations only, starting with thermal gradient holes in late 2010. Drill sites located in defined wetland areas require further approval from the US Army Corps of Engineers which is expected in Q1 2011. In November 2010, NGP and Ormat Nevada Inc., a wholly-owned subsidiary of Ormat Technologies Inc. entered into an agreement to jointly develop, construct, own and operate one or more geothermal power plants at the Crump Geyser Project Area. The parties formed the Crump Geothermal Company LLC ("CGC"), owned on a 50:50 basis. Under the Agreement between NGP and Ormat, NGP will contribute its title and interest in Crump Geyser Project geothermal leases, technical and engineering data, existing permits and the benefit from the on-going Department of Energy (DOE) cost-share grant for exploration in relation to the Crump Geyser area. Ormat will fund 100% of the initial development activities of CGC in the amount of US$15 million and pay NGP US$2.5 million in installments over a three year period. NGP has the option to borrow under a bridge financing facility from Ormat for all or part of NGP's share of costs up to US$15 million. Any bridge loans extended to NGP by Ormat will mature on the earlier of CGC obtaining third party non-recourse financing or upon achieving commercial operations, with an additional 90- day extension for any portion of bridge debt to be repaid from proceeds of the Treasury Cash Grant. Ormat will be the EPC contractor for the power plant which will utilize Ormat's proprietary generating and other balance of plant equipment. CGC is proceeding with drilling of a full size production well (43-3) designed to intersect the producing fault at depth and confirm reservoir temperatures and permeability. It is expected that 53


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54 production, slim-hole and gradient drilling and further characterization of the reservoir will occur throughout 2011, and will rapidly lead into production and injection development drilling. A total of $140,302 was expended on the Crump Geyser project during the 2010 fiscal year after the application of $134,189 in DOE funding. EDNA MOUNTAIN The Company leases, at Edna Mountain, cover a 12 square mile (7,072 acre) parcel of land. Location Our Edna Mountain property is located a few miles northeast of NGP's Pumpernickel Valley project, two miles south of Interstate Highway 80, and nine miles west of the Valmy coal-fired power plant owned by NV Energy and Idaho Power. EDNA LEASES Particulars with respect to our Edna leases are as follows: Owner
     Lease No.
     Sections
     Acreage
     Effective Date
     Expiry Date1
     BLM
     N88435
     4, 6, 8
     2022.16
     June 1, 2010
     May 31, 20202
     BLM
     N88436
     16, 18, 20, 30
     2490.52
     June 1, 2010
     May 31, 20203
     BLM
     N88437
     26, 28, 32, 34
     2560.00
     June 1, 2010
     May 31, 2020
 1. BLM Leases N88435, N88436 & N88437 As a competitive lease, in the first year of the primary term the Company is required to make rental payments of $2.00 per acre. During years two through ten of the lease, the Company is required to make payments of $3.00 per acre. By the end of the 10th year, the Company must expend a minimum of $40 per acre in development activities in order to be able to renew the lease. We are committed to pay BLM royalty rates for geothermal resources produced for commercial generation of electricity 1.75% for the first 10 years of production and 3.5% after the first 10 years. The royalty rate is to be applied to the gross proceeds derived from the sale of electricity. The royalty rate for by-products derived from geothermal resource production that are minerals is 5%, except for sodium compounds for which the royalty rate is 2%. Edna Description, History and Development The Edna Mountain property is located within Pumpernickel Valley along the eastern range front of Edna Mountain, several miles north of the Pumpernickel Valley project. This blind prospect was first identified during a USGS regional exploration campaign, and was referred to as the Kemp Anomaly, named after a local survey benchmark. The USGS campaign identified a thermal anomaly of approximately one square mile and intersected a shallow outflow plume with 54


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55 a thermal gradient hole. NGP has subsequently discovered two previously unknown stock watering wells in the area that exhibit significant thermal gradients between 100-130°C/km, and geothermometry analysis suggesting parent fluid temperatures of approximately 200°C. The discovery of these wells greatly expands the assumed areal extent of the thermal anomaly from ~ 1 mi2to an estimated 3 mi2. NGP obtained the federal geothermal leases at the Edna Mountain prospect in June, 2010, and is currently developing and preparing to implement an exploration strategy. A Notice of Intent (NOI) has been submitted to the Nevada Bureau of Land Management (BLM) to conduct a two-meter temperature survey in the first phase of exploration. This initial work will be followed by a series of thermal gradient holes and geophysical surveys in 2011. A total of $29,488 was expended on the Edna Mountain project during the 2010 fiscal year. ITEM 4A. Unresolved Staff Comments None. ITEM 5 Operating and Financial Review and Prospects A. Operating Results The information in this section is presented in accordance with Canadian Generally Accepted Accounting Principles. The following discussion of our financial condition and results of operations for the fiscal years ended June 30, 2010, June 30, 2009, and June 30, 2008, should be read in conjunction with our consolidated financial statements and related notes attached thereto. Although the Company has successfully declared commercial operation at its Blue Mountain power plant facility, there exists substantial doubt regarding the going concern assumption since the Company has no track record of operating profitably, and the Company must increase power production and further repay the TCW loan to meet loan covenants, such as a covenanted interest coverage ratio. The Companys ability to continue on as a going concern is dependent on meeting the covenants of its loan agreements, the achievement of profitable operations, completing its current drilling program successfully and increasing power production covered by its PPA with NVE and raising additional capital from lenders, shareholders and other investors to support ongoing business activities. The consolidated financial statements do not reflect adjustments to the carrying value of assets and liabilities, the reported expenses and other income and balance sheet classifications used that would be necessary if the going concern assumption were not appropriate. Such adjustments could be material. Accounting Policies Our significant accounting policies are discussed in Note 2 to the financial statements. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. On a regular basis, we evaluate our estimates and assumptions. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying 55


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56 values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from managements best estimates as additional information becomes available in the future. Significant areas of estimation include the following: Estimates of the useful lives and residual values of property, plant and equipment:
Amortization of property, plant and equipment for the year ended June 30, 2010 amounted to $4,950,417, mostly related to plant and equipment and the wellfield at the Companys Blue Mountain plant. The useful lives of plant and equipment at the Blue Mountain plant were estimated to range between five and 30 years, with the majority of material assets having estimated useful lives ranging between 20 and 30 years. The wellfield was estimated to have a 20-year useful live. Changes in the assumptions regarding the useful lives of these assets could have a material impact on the Companys profitability.Assumptions made around estimated future cash flows relating to the TCW debt:
The TCW loan is accounted for using the effective interest rate method. This method requires that future cash flows associated with the liability be estimated. In the case of the TCW loan, there is no specific amortization schedule associated with the loan, since the repayment is based on available cash from the Blue Mountain project, as more fully described in note 13 to the financial statements. The future cash flows are also affected by the timing of any future repayment from other sources of cash, such as a potential tax equity financing or government grant. Changes in the estimates relating to future cash flows can change the amount of the liability reflected on the balance sheet, as well as the interest expense included in the income statement.Assumptions made as a part of the fair value calculations for the cash settled option:
The cash settled option is based on the expected value of the Blue Mountain project at the time of the exercise of the option, and is determined using a valuation model. The model incorporates assumptions regarding future profitability, future capital spending, interest rates and electricity prices, amongst others. None of these inputs can be estimated with certainty, and changes in the assumptions can have a material effect on the value of the cash settled option.The calculation of the fair value of the asset retirement obligation:
The fair value of the asset retirement obligation is based on estimates of the cost that will need to be incurred to retire the Companys Blue Mountain plant. There is uncertainty regarding both the amount of such costs, as well as the timing.The calculation of the stock-based compensation expense:
The calculation of stock-based compensation expense using the Black-Scholes model includes assumptions regarding inputs such as the expected life of options, the expected volatility of the Companys share price and the expected divided yield. None of these can be determined with certainty. 56


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57 Determining the realizable amount of future income tax assets:
The Company has not recognized a future income tax asset in respect of its non-capital losses carried forward for tax purposes, since it was not considered more likely than not that these future income tax assets will be realized.Recognition and measurement of contingent liabilities:
On September 13, 2010, NVE challenged the Companys force majeure claim relating to the January electrical failure. The Company does not believe it has any liability since it believes the challenge is without merit. The amount of any potential liability will depend on the number of PCs generated during the balance of the calendar year and the cost to NVE to replace the PCs. Uncertainty exists as to the likelihood of the potential liability, as well as the amount thereof.Cash flow forecasts used for the purpose of impairment testing:
A cash generating unit is considered to be impaired if the carrying amount exceeds the undiscounted cash flows expected from its use and eventual disposition. Determining the cash flows expected from the Companys Blue Mountain plant involves estimates regarding future profitability, future capital spending and electricity prices, amongst others. During 2010, the Company made the following changes to its accounting policies: a)
     Canadian Institute of Chartered Accountants (CICA) handbook section 3064, Goodwill and Intangible Assets In February 2008, the CICA issued handbook section 3064  Goodwill and Intangible Assets, which replaces Section 3062, Goodwill and Intangible Assets, and Section 3450, Research and Development Costs. This new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets and also prescribes the recognition and measurement of impairment losses. The Company implemented the new standard during the year, and reclassified software in the amount of $13,014 as at June 30, 2009 from property, plant and equipment to intangible assets. b)
     CICA handbook section 3862, Financial Instruments  Disclosures Section 3862 was amended during June 2009 to enhance the disclosure requirements regarding liquidity risk of financial instruments and to add new disclosure requirements about fair value measurements of financial instruments. The Company implemented the new standard in the year. (See Note 18(a)). c)
     CICA handbook section 1506, Accounting Changes In June 2009, Section 1506, Accounting Changes, was amended to exclude from its scope changes in accounting policies upon the complete replacement of an entity's primary basis of accounting. The amendment applies to interim and annual financial statements relating to fiscal years beginning on or after July 1, 2009. The Company has implemented the new standard during the year. 57


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58 Reconciliation to United States Generally Accepted Accounting Principles We prepare our financial statements in accordance with accounting principles generally accepted in Canada ("Canadian GAAP") which differ in certain respects from those principles that we would have followed had our financial statements been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP"). Differences between Canadian GAAP and US GAAP include: Deferred Exploration Expenditures Under Canadian GAAP, the Company capitalizes costs of exploration relating to its interests in geothermal properties. Under US GAAP, all such costs are expensed until the Company has determined that the property is economically feasible and capable of commercial production. The Company uses the following indicators of economic feasibility: A third party assessment of the resource. Contracts indicating the recoverability of expenditures. The development of an economic model indicating the feasibility of the project. Financing to complete the project. The Company determined that the Blue Mountain project was economically feasible on August 29, 2008. As a result, costs incurred after the determination of economic feasibility of the Blue Mountain project in the years-ended June 30, 2009 and June 30, 2010, have been capitalized. As at June 30, 2008, the Company had not yet identified economically recoverable reserves on any of its interests. Accordingly, under US GAAP, all exploration costs incurred were expensed during the year ended June 30, 2008. Capitalization of Interest Under Canadian GAAP, actual interest costs on borrowings incurred to finance the construction of property, plant and equipment and the development of geothermal properties are capitalized during the period of time that is required to complete and prepare the asset for its intended use. Under US GAAP, the amount of interest capitalized is calculated by applying a capitalization rate to the average amount of accumulated expenditures for the Blue Mountain project. Additionally, not all of the interest capitalized for Canadian GAAP was capitalized for US GAAP as some of the expenditures relating to the Blue Mountain project were expensed under US GAAP during the year ended June 30, 2009. Property, Plant and Equipment During the year ended June 30, 2010, construction for the Blue Mountain Faulkner I power plant was completed and the plant commenced operating commercially. Under CDN GAAP acquisition and deferred exploration and development expenditures relating to the project have been transferred to property, plant and equipment. Under US GAAP some of these exploration and development costs were incurred prior to economic feasibility and have been expensed. As a result the carrying value transferred to property plant and equipment and the related amortization of those costs differs under US GAAP. 58


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59 Recent Accounting Pronouncements Canadian GAAP: The Company has adopted the following standards subsequent to the end of the 2010 financial year: CICA handbook section 1582, Business Combinations, section 1601, Consolidated Financial Statements and section 1602, Non-controlling interests;CICA handbook section 3855, Financial Instruments; andEIC 175, Multiple Deliverable Revenue Arrangements. None of these standards had a material impact on the Companys financial statements. IFRS: The Company will be adopting International Financial Reporting Standards (IFRS) for financial years beginning on or after January 1, 2011, with its first annual report under IFRS for the year ending June 30, 2012, and its first interim report under IFRS for the quarter ending September 30, 2011. Comparative information in respect of the 2011 financial year will be provided in both cases. US GAAP: The Company adopted the following standards during the year ended June 30, 2010: The Financial Accounting Standard Board (FASB) Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles in accordance with FASB ASC Topic 105, Generally Accepted Accounting Principles (the Codification).
The adoption of the Codification only affected how specific references to GAAP literature have been disclosed in the notes to our consolidated financial statements;Issue No. 08-6 Equity Method Investment Accounting Considerations (EITF 08- 6) (Codified within ASC 323); andASC 820-10-65 formerly FASB Staff Position FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP 157-4). The adoption of these standards did not have a material effect on the Company's consolidated financial statements. The following standards have been adopted subsequent to the end of the 2010 financial year: ASC 860-10 Consolidation (formerly SFAS Statement No 166);Accounting Standards Update (ASU) No. 2009- 05, Measuring Liabilities at Fair Value (ASU 2009-05); 59


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60 ASU No. 2009-12, Investments in Certain Entities That Calculate Net Asset Value Per Share (or Its Equivalent) (ASU 2009- 12);ASU 2009-13, Revenue Recognition (ASC 605), Multiple-Deliverable Revenue Arrangements (ASU 2009-13), and ASU 2009-14 Software (ASC 985), Certain Revenue Arrangements That Include Software Elements (ASU 2009-14);ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements; andASU2010-11, Scope Exception Related to embedded Credit Derivatives (ASC 815). None of these standards had a material impact on the Companys financial statements. June 30, 2010 Compared to June 30, 2009 The Company completed construction of its Blue Mountain geothermal power plant during the second quarter of the 2010 fiscal year, and accordingly the 2010 financial year represents the Companys transition from a development stage business to a revenue generating operation. The Company generated revenue of $11,839,010 during the year, with a gross margin of $4,184,342. No revenue had been generated in prior years. The Company incurred operating expenses of $4,921,965 during the year, up from $3,363,418 during 2009, an increase of $1,558,547 or 46%. The most important reason for the increase was an increase in legal fees of $759,285, partly due to additional legal work required on matters such as resolving the claim in respect of the electrical incident, but also due to certain legal expenses that had previously been deferred as they were related to future financings that were expensed during the year when the financing alternatives were abandoned. Consulting fees also increased by $319,580, as the Company continues to explore strategic options. In addition, operating expenses increased because costs that had been capitalized to the Blue Mountain project during the construction phase are now expensed. The effect of a stronger CAD on the translation into USD of CAD denominated costs incurred at the Companys head office also contributed to the increase. The Net Loss for the year amounted to $17,243,828 or 19 cents per share, compared to $5,088,760 or 5 cents per share in 2009, mostly due to an increase in the interest expense of $15,365,331. The interest expense arose primarily from the TCW loan, and included non-cash interest of $6,221,851. Interest had been capitalized to the Blue Mountain project in prior years. The Company recognized a fair value loss of $901,552 on the cash settled option during the year, mostly due to the option percentage having increased from 7.5% to 12.5% upon the draw-down of the final $10 million of the TCW loan. $893,011 of financing expenses includes a prepayment penalty incurred when the TCW loan was repaid with the proceeds from the cash grant received during the year, as well as financing expenses incurred in respect of funding options that were abandoned in favour of the John Hancock loan. During the 2009 financial year, the Company designated its US subsidiaries as self-sustaining, and changed its reporting currency to the US dollar. This change resulted in a decrease of the foreign exchange loss from $1,737,199 million in 2009 to $85,116 in 2010. Total assets reflected on the balance sheet decreased with the receipt of a cash grant of $57,872,513 under Section 1603, Division B of the ARRA of 2009 in respect of the Blue 60


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61 Mountain project. This cash grant was applied to property, plant and equipment for accounting purposes, and was used to fund a repayment of $28,879,380 on the TCW loan, as well as further work on the Blue Mountain project. On October 29, 2009, NGP was granted $1,764,272 for the Crump Geyser Geothermal Project and $1,597,847 for the North Valley Geothermal Project from the United States Department of Energy (DOE). The DOE funding, combined with equal funding from NGP, when and if available, will be used to conduct confirmation work to further demonstrate the viability of geothermal resources at both projects. June 30, 2009 Compared to June 30, 2008 During the year ended June 30, 2009, the Company continued developing its Blue Mountain, Nevada property by drilling and completing production wells 14-14, 15-14, 17-14 and injection wells 57-15, 61-22, 58A-15 and 58B-15. In addition, the Company completed transmission line construction and 91% of the power plant. The Company spent $93,602,699 constructing the Blue Mountain Power plant and associated transmission and gathering assets, as well as $38,310,200 in geothermal property work, principally drilling. The Company used funds available from the $180 million TCW loan and net equity funds raised during May 2008. Given the growing pace of drilling activity and EPC work the Companys expenses and net loss increased to $5,088,760 or $(0.05) per share compared to a loss for the year ended June 30, 2008 of $3,425,767 ($0.04 per share). The net loss increase results primarily from a foreign exchange loss and undrawn commitment fees on the TCW loan, offset by decreased stock-based compensation expenses. Operating expenses also continue to increase with the size and scope of operations as the Company continued to invest in its Blue Mountain project. Engineering and project management work added to the increasing pace of drilling. Administration and consulting costs of $1,718,244 (2008  $1,105,949) continue to increase as the number of employees, as well as the size and complexity of operations, increase. Accounting and audit fees increased to $220,067 (2008 $50,386) due to the increase in the size and scope of operations, as well as increased regulatory requirements, such as from Sarbanes Oxley, pending changes to accounting polices (e.g. from International Financial Reporting Standards (IFRS) and due to the complexity of accounts (e.g. the cash settled option valuation, US tax considerations and loan accounting). A one-time recruitment fee of $129,875, paid to Mr. Fairbank during 2008 when the Company purchased certain assets of Fairbank Engineering Ltd and hired the former employees, did not recur. Convention and publishing costs as well as investor relations expenses of $249,154 (2008 $455,457) declined as a result of a reduction in third party investor relations services and careful management in light of the limited financing activity year to date. The Company recorded a non-cash stock-based compensation expense of $307,359 (2008 $858,890), which was lower than the previous year due primarily to a lower stock price and partial vesting at the end of the year. Also, the Company recorded a non-cash loss resulting from the charge relating to the change in fair value of the cash settled option of $61,343 (2008  $nil). The foreign exchange loss results from application of the temporal method of foreign subsidiary exchange accounting during the first fiscal quarter. The Company designated its US subsidiary self sustaining and began reporting in US dollars at October 1, 2008. Proceeds in excess of mineral property costs will not continue since Sierra Geothermal Power stopped funding the Pumpernickel project. Losses are partially offset by interest income $346,520 (2008  $313,783). 61


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62 Foreign Currency Exchange Rates A portion of our business is conducted in currencies other than the United States dollar. As a result, we are subject to exposure from movements in foreign currency exchange rates. We do not currently engage in hedging transactions designed to manage currency fluctuation risks. Please refer to Note 2.c "Foreign Currency Translation" in our June 30, 2010 financial statements, which form a part of this Annual Report. Inflation Inflation has affected our business somewhat since capital costs increased from the time of signing our PPA and the time we committed to project costs. We have managed the risk with fixed price contracts wherever possible and will continue to manage the risk in the future. Interest Rate Sensitivity While the maturity date for our TCW credit facility is November 30, 2023 the Company must refinance at lower rates to remain viable and its primary interest rate risk is associated with refinancing. We do not currently engage in hedging transactions designed to manage interest rate fluctuation risks. B. Liquidity and Capital Resources Cash and Financial Condition The Companys operations do not currently generate positive cash flow. While we anticipate positive cash flow from operations during calendar 2011 we do not anticipate generating sufficient funds to cover all administrative expenses. Consequently, our financial success continues to rely on managements ability to expand capacity at Blue Mountain profitability, as well as find and develop other new economically viable geothermal resources. The recent venture with Ormat is an example of this work. However, generating sufficient cash flow to fund corporate operations may take many years. It involves many factors that are beyond our control. On August 29, 2008, to complete Blue Mountain construction, the Company closed a financing with TCW, a New York based investment management firm, for an amount of up to $180 million. The principal terms of the TCW loan are as follows: -
     14% interest per annum, payable quarterly, over a 15 year term maturing November 30, 2023;-
     Accrued interest up to 6% per annum may be deferred if enough cash is not available to fund the full interest payments;-
     The principal will be repaid from available cash flow  the lender has the right to receive cash interest plus 60% of available project cash, which will increase to 100% if target loan principle balances are exceeded;-
     Upon the earlier of repayment of the debt and maturity, the lender can exercise a cash settled option for a nominal exercise price and receive in cash an amount equal to 12.5% of the fair market value of the equity of Holdco.-
     The loan may be refinanced under certain circumstances. Refinancing of the balance in excess of $70 million prior to September 2, 2011 is subject to a 10% prepayment fee if from grant proceeds and, prior to March 2, 2012, 15% if from
 62


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63 equity issuances, proceeds of asset disposition or tax equity proceeds. Refinancing of the balance below $70 million, and the total balance after March 2, 2012 is subject to a make-whole premium equal to the difference between the present value of the remaining payments discounted at the yield of similar maturity United States Treasury securities and the principal amount of the loan being repaid; The financing provided by TCW is secured by a pledge of all the equity interest in Holdco, the owner of the equity NGP I. In addition, as of September 3, 2010, John Hancock has a first priority lien on certain bank accounts established in connection with the project to hold the proceeds of advances and revenues generated by operations, as well as all NPG Is assets that include leases, the electricity generation plant and transmission line. On September 3, 2010 the Company closed a financing with John Hancock Life Insurance for $98.5 million, 80% guaranteed by the US government under the Financial Institutions Incentive Program (FIPP) The principal terms of the John Hancock loan are as follows: -
     The U.S. Department of Energy (DOE) has guaranteed 80% of the principal and interest of the loan;-
     The proceeds of the John Hancock loan were used for partial repayment of the TCW loan, funding of security requirements under the PPA, funding of reserve accounts, and certain transaction costs;-
     A maturity date of December 31, 2029;-
     An interest rate of 4.14%;-
     Payments are to be made quarterly, consisting of a blend of principal and interest;-
     The John Hancock loan is a senior secured obligation of NGP I;-
     John Hancock has first priority security interest in NGP Blue Mountain Holdco LLCs equity interest in NGP I and all NGP I assets; and-
     Additional repayments in whole or in part, are subject to a Make Whole Amount. The Make Whole Amount is calculated as the excess of the discounted value of the remaining scheduled payments over the principal being repaid. The discounted value is calculated using the reinvestment yield, which is calculated as 0.5% over the yield to maturity of the US treasury securities with a maturity equal to the remaining average life of the principal being repaid.
 As at June 30, 2010, the Company was not in compliance with certain of the terms of the TCW loan agreement, principally those relating to the project capital costs, and while no event of default was asserted, the loan was presented as a short-term liability. At June 30, 2010, the Company had $6,435,375 in cash and equivalents on hand, and a working capital deficiency of $145,818,712. Following the year end, during the third calendar quarter the Company paid the TCW loan down to approximately $86 million and, in exchange for 4.5 million warrants exchangeable into Company shares at CAD 1.50 TCW waived the previous non compliance. As a result, on September 30, 2010 NGP 1 was in full compliance with loan terms and the loan was reclassified long term. Also, during the third calendar quarter the Company issued common shares from treasury and closed a $98.5 million debt financing with John Hancock. At September 30, 2010 the Company had $12.5 million in cash and equivalents on hand and working capital of $4.7 million. To maintain compliance with the TCW loan covenants, specifically the debt service coverage ratio, beyond December 2011 the Company must reduce the TCW loan balance to a maximum of $70 million and also increase power production to at least 40 MW. The Company is in the 63


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64 process of negotiating future funding, including a second cash grant and a financing that may monetize some tax benefits. The Company has $8.4 million set aside from the recent John Hancock loan with which to continue drilling that if successful should facilitate an increase in power production. Failure to meet the debt service coverage ratio will give rise to an event of default under the TCW loan agreement, and could give rise to the entire balance of the loan becoming due immediately. Since November 20, 2010 an NVE waiver and/or PUC approval is required to increase power supply nomination under the PPA. In addition, to increase power production, the Company requires lender approval, which is subject to a third party engineering report supporting a sustainable increase. The Company believes the current drilling program and financing work will be successful, and also, as long as there are no significant unforeseen expenses nor a revenue shortfall, that it can manage its cash obligations at current power production levels. However, there is no guarantee of success. Further complicating the current situation is a recent NVE challenge to the Companys Force Majeure claim relating to the January electrical outage. The Company believes the challenge is without merit and also that a potential claim is small. However, the claim will depend upon power production until year end and the cost of RECS to NVE. Neither of these variables is known at this time. The Company believes it will be successful increasing power production and raising additional funds with which to further repay the TCW loan, either through monetizing tax benefits or through an additional ARRA cash grant. The Company will be subject to a 10% Alternative Yield Maintenance Premium (AYMP) if a repayment is made from grant proceeds prior to September 2, 2010, and to a 15% AYMP if a repayment is made from equity issuances, proceeds of asset dispositions, grant proceeds or tax equity proceeds before March 2, 2012. Repayments thereafter are subject to a Yield Maintenance Amount (YMA), equal to the difference between the present value of the remaining scheduled payments discounted at a US Treasury rate and the amount of principal being repaid. In the event that cash flows available for the repayment of the TCW loan are not sufficient to cover the interest payment then due, interest up to a maximum of 6% may be deferred and added to the outstanding balance. Also, capital repayments may be deferred until November 30, 2023 if sufficient cash flows are not available earlier. However, the Company must increase power production and continue repayment of the TCW loan to maintain interest coverage covenant compliance. The table below presents a maturity analysis of the Companys financial liabilities at June 30, 2010 that shows the remaining contractual maturities: Carrying
     
     
     Contractual
     
     
     Within 1
     
     
     1 - 5
     
     
     More thanamount
     
     
     cash flows
     
     
     year
     
     
     years
     
     
     5 yearsLong-term leases
     $
     39,208
     
     $
     46,061
     
     $
     9,530
     
     $
     36,531
     
     $
     -Long-term payables
     
     680,645
     
     
     839,536
     
     
     276,979
     
     
     562,557
     
     
     -Long-term liability
     
     153,708,330
     
     
     238,575,958
     
     
     102,988,815
     
     
     57,717,160
     
     
     77,869,983Cash settled option
     
     2,722,396
     
     
     9,415,803
     
     
     -
     
     
     -
     
     
     9,415,803
 For balance sheet purposes as of June 30, 2010, the TCW liability has been classified as short-term, since the Company was not in compliance with all the terms of the loan agreement. The contractual cash flows presented above were calculated with reference to the total expected cash flows over the expected life of the liability. Actual cash flows could ultimately differ in timing 64


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65 and/or amounts. The total cash repayable will also be affected by the amount of the available cash flow from the project as well as the terms of any future potential refinancing of the liability. During fiscal 2010 the Companys investing activities were funded primarily by proceeds from the TCW loan facility. Its operating activities were funded primarily by revenue of $11,839,010 generated from electricity sales as well as the remaining net proceeds from private placements of the Companys securities during 2008 and the proceeds of options and agents options exercised. Operating Activities Cash used for operations during fiscal 2010 amounted to $7,534,974 (2009: 2,884,671; 2008: $4,817,934), and included a net loss of $17,981,451 (2009: $5,088,760; 2008: $3,425,767). Investing Activities During 2010, our cash inflow from investing activities was $19,841,759 after the receipt of a cash grant of $57,872,513 during the year (2009: outflow of $123,794,896; 2008: outflow of $32,870,692). Financing Activities During the fiscal year ended June 30, 2010, we drew $19,989,898 (2009: $139,292,591; 2008: $20,166,304) from our long-term liabilities and repaid $28,879,380 (2009: $20,723,093; 2008: nil). We also received $455,335 (2009: $94,899; 2008: $349,337) from the exercise of stock options and $297,985 (2009 & 2008: nil) from the exercise of agents options. A total of 1,029,000 common shares were issued at various times throughout the 2010 fiscal year (2009: 378,000; 2008: 17,345,333). Plan of Operations Our plan of operations for the fiscal year ending June 30, 2011 includes the following: We intend to continue focusing on the following tasks: -
     Work at our Crump property supporting the venture with Ormat that is intended to bring a 30 MW plant on line by December 31, 2013.-
     Complete an $8.4 million drilling program at Blue Mountain that will demonstrate sustainable higher power production at the project, resulting in lender approval to produce more power, following NVE approval to increase the supply nomination and begin supplying more than 40 MW.-
     Raise additional lower cost capital to pay TCW down to at least $70 million-
     Develop Pumpernickel-
     Capitalize opportunistically on consolidation opportunities that will reduce cost of capital
 65


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66 Outstanding Material Commitments for Capital Expenditures: The Company has few commitments for capital expenditures relating to its projects that will not be paid from the $8.4 million reserved from the John Hancock loan and the joint venture financing that is committed under the Ormat Joint Venture agreement. However, if the current drilling program at Blue Mountain is unsuccessful additional capital will be required. Project Financing:As of November 15, 2010, $8.4 million from the September John Hancock loan is reserved to fund continuing drilling to optimize power production. The Company has begun to generate revenue but does not expect sufficient Blue Mountain income to provide further project investment. The Company further believes future financing, potentially incorporating some of the projects tax benefits, will be successful. The Company must increase power production and further repay the TCW loan to maintain interest coverage covenant compliance. Permitting.Our permitting activities are continuing as projects develop. For more detailed information respecting the status of required permits for our Blue Mountain project, please refer to the heading "Property, plant and equipment" under Item 4.D. above. Potential Acquisitions.We intend to continue our growth through the acquisition, as funding and opportunity permits, of leasehold interests in properties and/or property rights that we believe will add to the value of our geothermal resources. Outstanding Share Data As at June 30, 2010, we had 95,576,504 common shares issued and outstanding. As of June 30, 2010, the following rights to purchase our securities were outstanding: (a)
     Stock options
     
     8,491,500(b)
     Share purchase warrants
     
     -8,491,500
 Subsequent to our 2010 fiscal year end, a total of 20,000 stock options were exercised at CDN$0.45, and a total of 244,000 stock options expired and/or were forfeited, having exercise prices between CDN$0.45 and $1.03. As well, subsequent to the 2010 fiscal year end, a total of 4,500,000 warrants were issued to the Trust Company of the West (TCW), concurrent with the closing of the John Hancock loan. The warrants are exercisable at CDN$1.50 for a period of five years. If the Companys share price closes at CDN$2.00 or higher for a period of 20 consecutive trading days, the Company shall give written notice to TCW that if the warrants are not exercised within 30 days of the notice, the warrants shall expire. On September 27, 2010, the Company completed a non-brokered private placement for 20,700,000 units at a price of CDN$0.50 per unit. Each unit consists of one common share and one three year transferable share purchase warrant, with one warrant entitling the holder to purchase one additional common share of the Company at a price of CDN$0.70 per warrant share. If the Companys share price closes at CDN$1.00 or greater for a period of 20 consecutive trading days, the Company may accelerate the expiry date of the warrants, and in such case, the warrants must be exercised within 30 days. A finders fee of one million warrants (finders warrants) were issued as compensation, the finders warrants are exercise at CDN$0.50 per finder warrant, entitling the holder to one common share and one warrant, with one warrant entitling the holder to purchase one additional common share of the Company at a price of CDN$0.70 per warrant share. 66


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67 As of November 17, 2010, our issued and outstanding share capital consisted of 116,296,504 common shares, 8,227,500 common shares issuable pursuant to rights granted to purchase our securities, 25,200,000 share purchase warrants and 1,000,000 finders warrants (exercisable into one common share and one share purchase warrant), as provided below, would result in a fully-diluted share capital of 151,724,004 common shares. As of November 17, 2010, the following rights to purchase our securities were outstanding: (a)
     Stock options
     
     8,227,500(b)
     Share purchase warrants
     
     20,700,000(c)
     TCW warrants
     
     4,500,000(d)
     Finders warrants (entitling the holder to a share and a warrant)
     
     1,000,00034,427,500
 C. Research and Development, Patents, Licenses etc. We do not currently and did not previously have research and development policies in place for the past three years. D. Trend Information Historically, the geothermal industry in the United States has experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. During the 1990s, growth and development in the geothermal industry occurred primarily in foreign markets and only minimal growth and development occurred in the United States. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation and as a result of newly enacted legislative and regulatory incentives, such as state renewable portfolio standards. We see an increasing demand for energy generated from geothermal and other renewable resources in the United States; a general trend toward fossil fuel prices, as well as further introduction of renewable portfolio standards as the most significant trends affecting our industry today and in the immediate future, while acknowledging industry consolidation, that should result in a lower cost of capital, is underway. E. Off-balance Sheet Arrangements The Company has the following off-balance sheet arrangements relating to cash collateralized letters of credit supporting the Power Purchase Agreement (PPA) with NV Energy: Under the terms of the PPA with NVE, the Company is liable for the cost of alternative power and renewable energy credits in certain circumstances, particularly if the minimum power under the PPA is not available. Under terms of the PPA, the Company has cash collateralized $3,805,672 in letters of credit in favour of NVE, with the Bank of the West. During the year, the Company issued two additional letters of credit, secured by cash, in the amounts of $50,000 and $100,000, to the State of Oregons Department of Geology and Mineral Industries and Nevada Division of Minerals, respectively, as reclamation bonds. We do not have any other off-balance sheet arrangements. 67


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68 F. Tabular Disclosure of Contractual Obligations at June 30, 2010 We have entered into operating leases for premises, vehicles and geothermal resources. Our minimum annual commitments in each of the next five fiscal years and thereafter (including work commitments) are as follows: Contractual obligations
     
     Payments due by periodTotal
     
     
     Less than 1 year
     
     
     1  3 years
     
     
     4  5 years
     
     
     After 5 yearsLong-term debt
     $
     238,575,958
     
     $
     102,988,815
     
     $
     28,208,995
     
     $
     29,508,165
     
     $
     77,869,983Long-term payables
     
     839,536
     
     
     276,979
     
     
     553,959
     
     
     8,598
     
     
     -Capital lease obligations
     
     46,060
     
     
     9,530
     
     
     19,060
     
     
     17,470
     
     
     -Cash settled option
     
     9,415,803
     
     
     -
     
     
     -
     
     
     -
     
     
     9,415,803Asset retirement obligation
     
     11,964,587
     
     
     -
     
     
     -
     
     
     -
     
     
     11,964,587Operating leases
     
     4,736,275
     
     
     512,747
     
     
     1,064,570
     
     
     740,007
     
     
     2,418,951Purchase obligations
     
     645,381
     
     
     645,381
     
     
     -
     
     
     -
     
     
     -Total contractual obligations
     $
     266,223,600
     
     $
     104,433,452
     
     $
     29,846,584
     
     $
     30,274,240
     
     $
     101,669,324
 ITEM 6 Directors, Senior Management and Employees A. Directors and Senior Management The following information relates to our directors and officers: Brian D. Fairbank, B.A.Sc., P. Eng. 
President, Chief Executive Officer 
Director since April 1995 Mr. Fairbank is responsible for obtaining financing, managing day to day operations of NGP and our subsidiaries and for the development of strategic direction. Mr. Fairbank is a geological engineer, with 30 years of geothermal engineering, exploration and resource assessment, business management and project finance experience. He founded Fairbank Engineering Ltd. in 1986, specializing in international project development. He was project manager through the discovery of Canadas Meager Creek Geothermal Area (1978-1982), which was then operated by BC Hydro and Power Authority. He assisted in the development of a National Power Plan for Kenya, East Africa and subsequently consulted on a production drilling program which developed 60 megawatts of steam reserves to augment 45 megawatts of existing generating capacity at the Olkaria Power Station, Kenya. Mr. Fairbank is a long-standing member of the Geothermal Resource Council, a Past President of the Canadian Geothermal Energy Association and is currently on the Geothermal Resources Council Board of Directors. 68


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69 Andrew T. Studley C.P.A, M.B.A. P. Eng 
Chief Financial Officer since August 2007 Mr. Studley is responsible for the financial supervision of the affairs and business of NGP and our subsidiaries. Mr. Studley has over 24 years of experience in all areas of corporate planning, accounting, finance and administration for chemical, energy and environmental management to worldwide chemical companies, refiners and power companies. Mr. Studley started his career in finance with Imperial Oil Ltd., and later was promoted to National Manager Marketing and Business Development. He was Vice President of Corporate Planning with AT Plastics and most recently, Corporate Controller with Marsulex Inc. - an environmental management and outsourced service provider to worldwide chemical companies, refiners and power companies. Mr. Studley holds a Chemical Engineering Degree from the University of Toronto, an MBA from Harvard University and is a Certified Public Accountant (CPA). R. Gordon Bloomquist, Ph.D. 
Director since March 2003 Mr. Bloomquist, an internationally recognized geothermal expert, is currently a consultant to the World Bank regarding geothermal energy projects in eastern and central Eurasia and the African Rift area. As a past Director of Geothermal and Integrated Energy Programs with the Washington State Energy Office, Dr. Bloomquist was responsible for all state geothermal policy decisions, technical assistance to geothermal resource developers, investigation of regional and local resources, and integrated energy project feasibility studies and programs. He has consulted with a wide variety of private corporations, utilities and institutions on legislative issues for geothermal development, power generation, environmental regulation and regional geothermal resource assessment. Dr. Bloomquist has been a Visiting Professor at the International School of Geothermics in Pisa, Italy, a member of the Geothermal Resource Council since 1972 (past Chairman and President) and has served on the Boards of the International Geothermal Association and the International District Heating Association. He is currently serving as the Chair of the International Geothermal Association 2010 World Geothermal Congress. Markus K. Christen 
Director since January 2003 Mr. Christen is a senior financial executive with extensive experience in investment and commercial banking both internationally and in the United States. He has been responsible for and involved in raising funds for projects in developed and emerging markets, including many geothermal plants. Mr. Christen received a law degree from the University of Zurich in 1981. He joined Credit Suisse in Zurich in 1983. From 1989 to 1996, he was a member of senior management, head of Project Finance and Structured Finance for Credit Suisse, New York, and he successfully led a global expansion with teams based in London and Hong Kong. From 1997 to 2000, Mr. Christen was Managing Director of Credit Suisse First Boston, New York where he was responsible for the acquisition and execution of major project finance transactions on a global 69


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70 basis. In 2000, Mr. Christen established an independent financial advisory practice specializing in mergers, acquisitions and project finance. Mr. Christen has extensive geothermal power industry contacts and project finance or project acquisition experience in Nevada (Brady, Desert Peak), California (Coso, Geysers, Salton Sea, East Mesa, Ormesa), Hawaii, Indonesia, and the Philippines (Mahanagdong, Malitbog Visayas, Upper Mahiao). Gavin Cooper, Chartered Accountant 
Director since June 2009 Mr. Cooper is a Chartered Accountant with a Bachelor of Accounting (Hons) from the University of South Africa and has more than 20 years of experience in senior executive management roles. He served as Chief Financial Officer from 2003 to 2008 with VRB Power Systems Inc. (a flow battery energy storage development company), President and CEO of Catamaran Ferries International Inc. through the wind-up phase of the BC Government's fast ferries program, Director of Finance and Administration at Yarrows Ltd., Vice President and Director of Pacific Engineered Materials Inc., and Senior Audit Manager at Ernst & Whinney in Vancouver, BC; London, UK; and Cape Town, South Africa. Domenic J. Falcone, CPA 
Director since January 2004 Mr. Falcone is currently an independent financial consultant. He was a senior executive of Geothermal Resource International Inc. (1971 to 1987), a power developer in California that played a significant role in building a viable U.S. geothermal industry. Mr. Falcone has an extensive background in geothermal project financing, acquisitions and business development, and a broad knowledge of the independent power and energy industries. As President and principal of Domenic J. Falcone Associates Inc. from 1987 to 1991 and 1997 to current, he provides project financing and financial services to the independent power, co-generation, solid waste and wastewater industries. Mr. Falcone was Chief Financial Officer and Vice President of PG&E Energy Services during its start-up period and was President of Creston Financial Group (1991-1997). Mr. Falcone received the Joseph W. Aidlin Award in 1991 from the Geothermal Resources Council recognizing his outstanding contribution to the development of the geothermal resources industry. Mr. Falcone is a long-standing member of the Geothermal Resources Council and a board member of the Geothermal Energy Association. James Ernest Yates 
Director since December 1996 Mr. Yates is an independent businessman with 20 years of experience in corporate development and financing of start up resource companies. Mr. Yates financed and developed to production the Crowfoot Lewis open-pit gold mine in Nevada and is currently a director of ESO Uranium Corp., a mineral exploration company focused on uranium exploration, and Canyon Copper, an exploration and resource company with an advanced mineral resource property in Nevada. The following information relates to our non-director/officer senior management and consultants upon whose work we are dependent: 70


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71 Kim Niggemann, B.Sc., Geologist 
V.P. Resources Ms. Niggemann is the V.P. Resources responsible for resource development on all existing properties and new acquisitions. She oversees all aspects of the geology, geochemistry and geophysics, drilling and reservoir engineering operations, leases, land, environmental and regulatory compliance, program efficiency, budget control and contracts. Ms. Niggemann obtained a B.Sc. degree in geology from the University of New Brunswick in 1980 and worked with the Department of Natural Resources of New Brunswick, Shell Canada, and Home Oil in eastern Canada before joining Chevron Resources in Vancouver, B.C. Chevron field projects included potash deposits in Cape Breton, mining exploration in the Yukon and British Columbia, and major field involvement in drilling at the Muddy Lake gold discovery. Muddy Lake was later developed as the Golden Bear Mine. Ms. Niggemann took a sabbatical from mineral exploration in 1990. In 2001, she obtained a Management Systems Certificate with honours from the British Columbia Institute of Technology (BCIT) and gained business management, project accounting, bookkeeping and consulting experience working on contracts for the Insurance Corporation of British Columbia (ICBC) and small businesses. Since joining the NGP team in 2003, Ms. Niggemann has successfully fulfilled three US DOE contracts for slim well drilling and geophysics under the GRED program which resulted in the success of the 49.5MW nameplate Blue Mountain Geothermal Power Plant in Humboldt County, Nevada. Max Walenciak P.EngSenior V.P. Operations and Development Mr. Walenciak is a registered professional engineer with over 30 years of diverse project management experience including both gas-fired and geothermal power plants. His experience includes project planning, design development, permitting support, negotiation of key project development and operation agreements, and operations of power plants and associated facilities. He has an in-depth understanding of the design, procurement, and construction process from the owner/developer's perspective. Mr. Walenciak is responsible for engineering, equipment procurement and contractor selection for the Company's planned 'Faulkner 1' geothermal power plant, well field and transmission line at Blue Mountain, Nevada. Mr. Walenciak will direct critical path scheduling and manage the overall construction effort. Subsidiaries The following persons are the directors and officers of our wholly-owned subsidiaries: Blue Mountain Power Company
     Brian Fairbank
Andrew Studley
Gordon Bloomquist
     President, and Director
CFO and Secretary
DirectorNGP Chile Ltda.
     Brian D. Fairbank
     President, and Director
 71


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72 Stephanie Diane Ashton
Cesar Andres Lopez Alarcon
     Director
DirectorNevada Geothermal Power Company
     Brian Fairbank
Andrew Studley
     President, and Director
CFO and SecretaryNevada Geothermal Operating Company LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentDesert Valley Gold Co.
     Brian Fairbank
     President, CFO, Director and SecretaryNGP Blue Mountain Holdco LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentNGP Blue Mountain Holdco II LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentNGP Blue Mountain Holdco III LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentNGP Blue Mountain Holdco IV LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentNGP Blue Mountain I LLC
     Brian Fairbank
Andrew Studley
Markus Christen
Scott McInnes (1)
     President, and Director
CFO and Secretary
Vice President
DirectorNGP Blue Mountain II LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentNGP Blue Mountain III LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentNGP Blue Mountain IV LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President, and Director
CFO and Secretary
Vice PresidentNGP (Black Warrior I)
     Brian Fairbank
Andrew Studley
     President and Director
Secretary and TreasurerNGP (Crump I)
     Brian Fairbank
Andrew Studley
     President and Director
Secretary and TreasurerNGP (Pumpernickel I)
     Brian Fairbank
Andrew Studley
     President and Director
Secretary and TreasurerNevada Geothermal Power US Holdings Inc.
     Brian Fairbank
Andrew Studley
Markus Christen
     President
Secretary and Treasurer
DirectorNevada Geothermal Power Holding Company LLC
     Brian Fairbank
Andrew Studley
Markus Christen
     President
Secretary and Treasurer
Director
 (1) Mr. McInnes is an independent director representing John Hancock and DOE on the Board of NGP Blue Mountain 1 LLC 72


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73 Family Relationships There are no family relationships between any of the persons named above. Other Relationships There are no arrangements or understandings between any major shareholder, customer, supplier or others, pursuant to which any of the above-named persons were selected as directors or members of senior management. B. Compensation We are required, under applicable securities legislation in Canada to disclose to our shareholders details of compensation paid to our executive officers. The following fairly reflects all material information regarding compensation paid to our executive officers, which has been disclosed to our shareholders under applicable Canadian law. The number of current Executive Officers of the Company is two (2), namely Brian D. Fairbank, President and CEO and Andrew T. Studley, Secretary and CFO. Name
     Principal Position
     From
     ToBrian Fairbank
     President
     April 1995
     PresentChief Executive Officer
     May 1995Andrew Studley
     Chief Financial Officer and Secretary
     Aug. 2007
     Present
 Summary Compensation Table Set out below is a summary of the compensation paid to the Chief Executive Officer and all Executive Officers receiving total compensation in excess of $150,000 (collectively Named Executive Officers) of the Company for the three most recently completed fiscal years is set out below: Name and Principal Position and Country of Residence
     Fiscal Year
     Annual Compensation
     Long Term Compensation
     All Other Compen-sation ($)Awards
     PayoutsSalary(CDN$)
     Bonus($)
     Other Annual Compen-sation (CDN$)
     Securities Under Option/SARs Granted (#)
     Restricted Shares or Restricted Share Units ($)
     LTIP Payouts ($)Brian D. Fairbank,President, CEOCanada
     2010
2009 2008
     255,000(1)
250,000(1)
214,500(1)
     nil
nilnil
     nil
nilnil
     67,000
402,000(2)
180,000
     nil
nilnil
     nil
nilnil
     nil
nilnil(3)
 73


---

74 Name and Principal Position and Country of Residence
     Fiscal Year
     Annual Compensation
     Long Term Compensation
     All Other Compen-sation ($)Awards
     PayoutsSalary(CDN$)
     Bonus($)
     Other Annual Compen-sation (CDN$)
     Securities Under Option/SARs Granted (#)
     Restricted Shares or Restricted Share Units ($)
     LTIP Payouts ($)Andrew T. StudleyCFO and Secretary
     2010
2009
2008
     172,507
164,781
138,077
     nil
nilnil
     nil
nilnil
     nil
100,000
390,000
     nil
nilnil
     nil
nilnil
     10,000
15,00015,000 (1) consisting of a management fees paid to Fairbank Engineering Ltd. and Tywell Management Inc., non- reporting companies controlled by Brian D. Fairbank.(2) indirectly through Tywell Management Inc., a private company controlled by Brian D. Fairbank.(3) the table does not include fees paid to Fairbank Engineering Ltd., a non-reporting company controlled by Brian D. Fairbank, for geothermal consulting services provided by employees of Fairbank Engineering Ltd. other than Brian D. Fairbank. The following table sets forth stock options granted by us during the fiscal year ended June 30, 2010, to our current executive officers: Option/SAR Grants During the Most Recently Completed Financial Year Name
     Securities Under Options/SARs Granted(#)
     % of Total Options/SARs Granted to Employees in Financial Year
     Exercise or Base Price (CDN$/Security)
     Market Value of Securities Underlying Options/SARs on the Date of Grant ($/security)
     Expiration DateBrian D. Fairbank
     67,000
     14%
     1.22
     1.22
     Oct. 16, 2014Andrew T. Studley
     nil
     0%
     n/a
     n/a
     n/a
 The following table sets forth details of all exercises of stock options during the fiscal year ended June 30, 2010 by our current executive officers: Name
     Securities Acquired or Exercised
     Aggregate Value Realized (1) (CDN$)
     Unexercised Options/SARs at June 30, 2010
     Value of Unexercised in-the-Money Options/SARs at 
June 30,2010(2)(CDN$)Brian D. Fairbank
     67,000
     39,530
     1,949,000
     94,420Andrew T. Studley
     nil
     nil
     490,000
     21,000
 74


---

75 (1) Aggregate Value Realized is calculated by determining the difference between the market value of the securities underlying the options or SARs at the date of exercise and the exercise price of the options or SARs and is not necessarily indicative of the value (i.e. loss or gain) actually realized by the Named Executive Officer.(2) This represents the closing price of the Companys shares on the Exchange (being CDN$0.66) on the last day the shares traded on or before June 30, 2010 (being June 30, 2010) less the per option exercise price. The following table sets forth details of all stock options granted during the fiscal year ended June 30, 2009: Name
     Securities Under Options/SARs Granted(#)
     % of Total Options/SARs Granted to Employees in Financial Year
     Exercise or Base Price (CDN$/Security)
     Market Value of Securities Underlying Options/SARs on the Date of Grant ($/security)
     Expiration DateBrian D. Fairbank
     402,000
     20%
     $0.45
     nil
     Jan. 21, 2014
Mar. 4, 2014
Mar. 19, 2014Andrew T. Studley
     100,000
     5%
     $0.45
     nil
     Mar. 19, 2014
 No options held by any executive officer were re-priced downward during our most recently completed financial year. We do not provide retirement benefits for directors, officers, employees or consultants. No funds were set aside or accrued by us during the fiscal year ended June 30, 2009 to provide pension, retirement or similar benefits for our directors or officers pursuant to any existing plan provided or contributed to by us or our subsidiaries. Compensation of Directors Following are our policies regarding the compensation of our directors and others: (a)
     The Company pays each director the sum of CDN$1,000 per month, or CDN$1,500 per month for the Chairman of a Committee.(b)
     Directors and non-director committee members are compensated for their actual expenses incurred in the pursuance of their duties.(c)
     Directors may be compensated for services rendered as consultants or experts.(d)
     Directors may be awarded special remuneration, if such director undertakes any special services on our behalf, other than services ordinarily required of a director.(e)
     A committee chairman receives the aggregate sum of CDN$18,000 per fiscal year, regardless of the number of committees that such person may chair.(f)
     A non-chair committee member receives the aggregate sum of CDN$12,000 per fiscal year, regardless of the number of committees that such person may contribute to. 75


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76 In connection with the policies above, for the fiscal year ended June 30, 2010, the Company paid an aggregate of $72,055 (CDN$76,000) to the directors of the Company for all services rendered in connection with the directorship. We carry CDN $10 million in director and officer liability insurance. The Company paid Markus Christen, a director of the Company, the sum of $252,307 for consulting services during the 2010 fiscal year pursuant to an agreement dated January 12, 2007. Mr. Christen is also entitled to receive fees for financial advisory services in connection with arranging financing for development and construction of a power plant at the Blue Mountain project. The Company paid Domenic Falcone, a director of the Company, the sum of $99,177 during the 2010 fiscal year as remuneration for consulting services. The Company has granted the following incentive stock options to directors, officers, consultants and employees of the Company during the Companys most recently completed financial year: Number Granted (1)
     Exercise Price per Share
     Date of Grant480,000
     CDN$0.64 - $1.22
     July 20, 2009  March 12, 2010
 (1) includes the number granted to Named Executive Officers previously disclosed
 No options held by a non-executive officer director were re-priced downward during our most recently completed financial year. C. Board Practices Terms of Office Name
     Position
     Office Held Since
     Expiration of Current Term of OfficeBrian D. Fairbank
     President, CEO, Director
     Director since April, 1995.
     December, 2010 for directorship.  Not applicable for other positions listed.R. Gordon Bloomquist
     Director
     Director since March, 2003.
     December, 2011Markus K. Christen
     Director
     Director since January, 2003.
     December, 2011Domenic J. Falcone
     Director
     Director since January, 2004.
     December, 2011Gavin Cooper
     Director
     Director since June, 2009.
     December, 2011James Ernest Yates
     Director
     Director since December, 1996.
     December, 2011
 The election and retirement of our directors are provided for in our articles. An election of directors takes place at each annual meeting of shareholders and all the directors then in office retire but, if qualified, are eligible for re-election. A director retains office only until the election of his successor. The number of directors to be elected at such meeting is the number of directors then in office, unless the directors or the shareholders otherwise determine. The election is by ordinary resolution of shareholders. If an election of directors is not held at the 76


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77 proper time, the incumbent directors continue in office until their successors are elected. Our last annual general meeting was held on December 7, 2010. The Board is currently composed of six directors, three of whom (Messrs. Cooper, Yates, and Bloomquist) are independent. The remaining directors (Messrs. Fairbank, Falcone and Christen) are not considered to be independent as a result of their work for the Company. Our Articles also permit the directors to add additional directors to the Board between annual general meetings as long as the number appointed does not exceed more than one-third of the number of directors elected at the last annual general meeting. Individuals appointed as directors to fill casual vacancies created on the Board or added as additional directors hold office like any other director until the next annual general meeting at which time they may be re-elected or replaced. Our officers are re-elected at a directors meeting following each annual general meeting. Directors Service Contracts. None of the directors have contracts providing benefits upon termination of their service as a director. Audit and Remuneration Committees. We have established the following committees: Compensationand
     CorporateAudit
     Nominating
     GovernanceDomenic Falcone*
     Gavin Cooper*
     Domenic Falcone *James Yates
     Markus Christen
     James YatesGavin Cooper
     Domenic Falcone
     Markus ChristenGordon Bloomquist
     James Yates
     Gavin Cooper* Chairman of the Committee
  Audit Committee Our Audit Committee is appointed by the Board, and its members hold office until removed by the Board, their resignation, or until our next annual general meeting, at which time their appointments expire and they are then eligible for re-appointment. The Audit Committee operates pursuant to a charter adopted by the Board, and reviews and approves the scope of the audit procedures employed by our independent auditors, reviews the results of the auditors examination, the scope of audits, the auditors opinion on the adequacy of internal controls and quality of financial reporting and our accounting and reporting principles, policies and practices, as well as our accounting, financial and operating controls. The audit committee also reports to the Board with respect to such matters and recommends the selection of independent auditors. Before the financial statements are presented to the shareholders at an annual general meeting they are submitted to the audit committee for review with the independent auditors, following which the report of the audit committee on the financial statements is submitted to the Board. 77


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78 The quarterly unaudited consolidated financial statements prepared by management and the quarterly Management and Discussion Analysis are also submitted to the audit committee for their review prior to dissemination to the shareholders. Compensation and Nominating Committee This committee is responsible for, among other things, undertaking an annual review of the efficiency of our organizational structure, identifying candidates for election to the Board and/or committees, and reviewing succession practices for management, and the performance of management. It is also responsible for undertaking an annual review of compensation for management and for directors who serve on committees, developing compensation guidelines for management, administration of the incentive stock option plan and reporting to the Board on its activities and recommendations. Corporate Governance Committee This committee is responsible for monitoring the governance practices and procedures of our Board, as well as the effectiveness of the Board and all committees of the Board. D. Employees The Company had 37 employees as of the end of the fiscal year ended June 30, 2010. Twelve employees were hired over the past two years to operate the Blue Mountain Faulkner 1 geothermal power plant. With the exception of plant employees, there has been no material change in the number of employees during the past three financial years. E. Share Ownership The following table sets forth the share ownership of our directors and officers, and includes the details of all options or warrants to purchase shares of NGP held by such persons as of November 17, 2010. Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission. In computing the number of common shares owned by a person and the percentage ownership of that person, common shares subject to options and warrants held by that person that are currently exercisable or exercisable within 60 days of November 17, 2010, are deemed outstanding. Such shares, however, are not deemed outstanding for the purposes of computing the percentage ownership of any other person. 78


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79 Name
     Number of
Common Shares (1)
     Number of Common Shares Subject to Options or Warrants
     Beneficial Percentage Ownership
     Exercise
Price (CDN)
     Expiry
DateBrian Fairbank
     6,910,053
     162,000
80,000
160,000
1,000,000
300,000
180,000
67,000
     5.9%
     $0.45
$0.45
$0.45
$0.65
$0.90
$1.03
$1.22
     Jan 21/14
Mar 4/14
Mar 19/14
Apr 04/12
Jan 18/11
May 27/13
Oct 16/14Andrew Studley
     100,000
     250,000
50,000
90,000
100,000
     0.1%
     $0.80  
$1.15
$1.03
$0.45
     Aug 1/12
Nov 21/12
May 27/13
Mar 19/14James Yates
     185,000
     175,000 150,000
90,000
35,000
83,000
     0.2%
     $0.90 
$0.65
$1.03
$0.45
$1.22
     Jan. 18/11 
Apr. 4/12
May 27/13
Mar 19/14
Oct 16/14Markus Christen
     710,000
     75,000  
475,000
90,000
100,000
100,000
35,000
     0.6%
     $0.90 
$0.65
$1.03
$1.02
$1.08
$0.45
     Jan 18/11 
Apr 4/12
May 28/13
July 11/13
Aug 14/13
Mar 19/14Gordon Bloomquist
     385,000
     150,000 255,000
90,000
35,000
50,000
     0.3%
     $0.90
$0.65
$1.03
$0.45
$1.22
     Jan 18/11 
Apr 4/12
May 28/13
Mar 19/14
Oct 16/14Domenic Falcone
     760,000
     75,000  475,000
90,000
100,000
100,000
85,000
     0.6%
     $0.90 
$0.65
$1.03
$1.08
$0.45
$0.45
     Jan 18/11 
Apr 4/12
May 28/13
Aug 14/13
Mar 4/14
Mar 19/14Gavin Cooper
     250,000
     250,000
     0.2%
     $0.47
     May 28/14Richard Campbell(2)
     Nil
     nil
     nil
     N/A
     N/A
 79


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80 (1) These figures include options and warrants exercisable within sixty days. (2) Mr. Campbell resigned as a director in July 2009 The voting rights attached to the common shares owned by our officers and directors do not differ from those voting rights attached to shares owned by people who are not officers or directors of our Company. Stock Option Plan On December 4, 2008, we renewed and adopted a new stock option plan (the "Plan"), which authorizes our Board to grant incentive stock options to directors, officers, employees and consultants of NGP and our associated, affiliated, controlled or subsidiary companies, subject to the terms of the Plan and in accordance with the rules and policies of the governing regulatory authorities. Under the Plan, we may reserve up to 10% of our issued and outstanding common shares (on a non-diluted basis) for the granting of options from time to time. As a Tier 2 Toronto Stock Exchange (TSXV) company, the number of common shares that may be reserved for issuance to any one person during any 12 month period shall not exceed 5% of our issued and outstanding share capital, or in the case of a consultant or investor relations employee, 2%. As of November 17, 2010 the maximum number of shares reserved for issuance under the Plan was 11,629,650 common shares, of which a total of 8,227,500 have been granted, 8,197,500 are vested and 3,402,150 common shares available under the Plan for future granting. ITEM 7 Major Shareholders and Related Party Transactions A. Major Shareholders Beneficial Holders of 5% or More: As of November 20, 2010, we had 116,296,504 common shares issued and outstanding. To the best of our knowledge, the following table sets forth persons known to us to be the beneficial owners of five percent (5%) or more of our common shares: Name
     Amount Owned
     Percentage
of ClassWohlman Family(1)
     9,477,662
     8.15%Wellington Management Company, LLP(2)
     8,474,200
     7.29%Winslow(3)
     5,808,000
     5.00%
 (1)
     This includes multiple share holdings by the three members of the Wohlman family, Louis Wohlman and his adult sons Robert Wohlman and Doug Wohlman.(2)
     As of October 31, 2010, Wellington Management, in its capacity as investment adviser, may be deemed to beneficially own 8,474,200 shares of the Issuer which are held of record by clients of Wellington Management.(3)
     As of October 31, 2010 comprises of holdings from Winslow Management Company, LLC and Winslow Green Growth Fund 80


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81 Significant Changes in Share Ownership There has been a significant change in the percentage ownership held by major shareholders during the past three years. Wexford Spectrum Trading Limited since January 14, 2009 disposed of its holdings, 6,415,900 shares, bringing the amount of shares owned to zero. Voting Rights The voting rights of our major shareholders do not differ from the voting rights of holders of our Companys shares who are not major shareholders. Host Country Record Shareholders As of October 31, 2010, Computershare Investor Services Inc., our registrar and transfer agent, reported that we had 116,296,504 common shares issued and outstanding. Of those common shares, 66,817,420 common shares were registered to Canadian residents (31 shareholders), 43,443,251 common shares were registered to residents of the United States (121 shareholders) and 6,035,833 common shares were registered to residents of other foreign countries (7 shareholders). Controlling Ownership To the best of our knowledge, we are not directly or indirectly owned or controlled by another corporation, by any foreign government or by any other natural or legal person, severally or jointly. Arrangements Affecting Ownership There are no arrangements known to us, the operation of which may at a subsequent date result in a change in the control of our Company. B. Related Party Transactions Other than as disclosed below or elsewhere in this Annual Report, to the best of our knowledge, there have been no material transactions or loans during the past three fiscal years between our Company and: (a) enterprises that directly or indirectly through one or more intermediaries, control or are controlled by, or are under common control with, our Company; (b) associates; (c) individuals owning, directly or indirectly, an interest in the voting power of our Company that gives them significant influence over our Company, and close members of any such individuals family; (d) key management personnel of our Company, including directors and senior management of our Company and close members of such individuals families; and (e) enterprises in which a substantial interest in the voting power is owned, directly or indirectly, by any person described in (c) or (d) or over which such a person is able to exercise significant influence. (a) Nevada Geothermal Power Inc. entered into a letter agreement with Markus K. Christen, a director of NGP, dated January 12, 2007, which was amended July 2, 2007 and January 13, 2009. Pursuant to the terms of this agreement, Mr. Christen is providing consulting services in exchange for fees and out-of-pocket expenses. The consulting services are financial advisory services in connection with arranging financing for the Blue Mountain Project. Upon satisfaction of the conditions precedent, the Company paid success fees totalling approximately $2 million to 81


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82 Markus K. Christen (a director of the Company), in addition to a monthly fee ranging from $12 to $20 thousand. During fiscal 2010, the Company paid $252,307 to Mr. Christen for advisory services in connection for arranging financing for the Blue Mountain Project. (b) Amounts Payable to Directors, Officers, and Affiliated Companies As at June 30, 2010, a total of $68,040 was owing to directors, officers and companies controlled by directors of the Company for consulting services and directors fees. This amount is included in accounts payable and accrued liabilities, is interest free, unsecured and is repayable on demand. (c) Fees Paid to Directors, Officers, Former Officers, and Affiliated Companies During the years ended June 30, 2010 and 2009, the following were paid or accrued to directors, officers, and former officers and to companies controlled by directors of the Company: 2010
     
     
     2009Director fees
     $
     72,055
     
     $
     77,702Consulting, including financing success fees
     $
     351,484
     
     $
     1,184,131
  Consulting costs for 2009 primarily resulted from success fees paid to a director of the Company in connection with successfully arranging the Companys TCW loan and letters of credit in support of the Limited Notice to Proceed contracted with Ormat. (e) Employment Agreements. On October 1, 2007, the Tywell Management Agreement was terminated and replaced by an employment agreement whereby the Company retained the services of Mr. Brian Fairbank on a full-time basis for a period of two years in consideration of a payment of CDN $250,000 in salary per year, which was increased to CDN $270,000 On April 1, 2010. The agreement provides for severance payments equal to 24 months salary in the event of termination without cause, and up to 48 months salary if termination is a result of a change of control of the Company. C. Interests of Experts and Counsel This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. 82


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83 ITEM 8 Financial Information A. Consolidated Statements and Other Financial Information Financial Statements filed as part of this Annual Report Our financial statements are stated in US dollars and are prepared in accordance with Canadian generally accepted accounting principles. The following financial statements are filed as part of the Annual Report in Exhibits 9.1 and 9.2: Consolidated financial statements for the year ended June 30, 2010;Consolidated financial statements for the year ended June 30, 2009; Legal Proceedings On August 23, 2010, the Company settled all disputes that arose under the EPC contract as a result of the facility shutdown between January 16, and February 23, 2010, due to a short-circuit caused by faulty layout of underground cables. The settlement consisted of a cash payment of $1 million, power plant spares and extended warranties. Dividend Distributions Holders of our common shares are entitled to receive such dividends as may be declared from time to time by our board, in its discretion, out of funds legally available for that purpose. We intend to retain future earnings, if any, for use in the operation and expansion of our business and do not intend to pay any cash dividends in the foreseeable future. B. Significant Changes Other than as disclosed below, no significant change has occurred in our Companys financial statements since the subsequent events were disclosed in our Annual Financial Report at September 27, 2010. On November 1, 2010, the Company announced it has entered into a letter agreement under which the Company and Ormat Nevada Inc. (Ormat) will develop the Crump Geyser project on a 50:50 basis under a jointly formed limited liability company, Crump Geothermal Company LLC (CGC). Under the agreement, the Company will contribute its title and interest in the Crump Geyser project geothermal leases, technical and engineering data, existing permits and the benefit from the DOE cost-share grant for exploration in relation to the Crump geyser area. Ormat will finance 100% of the initial development activities of CGC in the amount of $15-million and pay the Company $2.5- million in installments over a three-year period. After the initial development expenses financed by Ormat are expended, the parties will each be responsible for financing their 50% share of costs; however, the Company has the option to borrow under a bridge financing facility from Ormat for all or part of the Company's share of costs up to $15- million. Any bridge loans extended to the Company by Ormat will mature on the earlier of CGC obtaining third party non-recourse financing or upon achieving commercial operations, with an additional 90-day extension for any portion of bridge debt to be repaid from proceeds of a treasury cash grant. If either party to the agreement fails to


83

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84 make its pro rata payment of an approved budget, the non-contributing party will be subject to customary dilution of its equity interest. If the Company is diluted, it will have an option to reinstate its 50-per-cent ownership position up to the date of commercial operation of the power plant. In no event will the Companys ownership interest be diluted below 20 per cent. If the parties elect to construct an expansion project, each party shall be entitled to participate with a 50-per-cent interest and dilution provisions will also apply except that the Company will not enjoy dilution protection with respect to expansions. ITEM 9 The Offer and Listing A. Offer and Listing Details Price History The high and low prices expressed in Canadian dollars on the TSX for our common shares and the high and low prices expressed in United States dollars quoted on the OTC Bulletin Board for the last six (6) months, each quarter for the last two (2) fiscal years and annually for the last five (5) years are as follows: TSX Venture Exchange
     Over-the-Counter
Bulletin BoardPeriod Ended
     High
     Low
     High
     Low2010
     CDN$
     CDN$
     CDN$
     CDN$November
     0.88
     0.62
     0.89
     0.61October
     0.67
     0.59
     0.66
     0.58September
     0.70
     0.48
     0.68
     0.46August
     0.61
     0.53
     0.58
     0.50July
     0.66
     0.53
     0.64
     0.52June
     0.84
     0.56
     0.82
     0.5320104th Quarter June
     0.84
     0.54
     0.82
     0.503rd Quarter
March
     1.04
     0.71
     1.00
     0.672nd Quarter
December
     1.26
     0.88
     1.21
     0.821St quarter
September
     1.15
     0.60
     1.07
     0.5220094th Quarter
June
     0.92
     0.45
     0.82
     0.373rd Quarter
March
     0.49
     0.35
     0.45
     0.26
 
 84


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85 TSX Venture Exchange
     Over-the-Counter
Bulletin BoardPeriod Ended
     High
     Low
     High
     Low2010
     CDN$
     CDN$
     CDN$
     CDN$2nd Quarter
December
     0.78
     0.28
     0.73
     0.221St quarter
September
     1.19
     0.65
     1.15
     0.62Annual 2010
     1.04
     0.48
     1.00
     0.46Annual 2009
     1.24
     0.35
     1.22
     0.26Annual 2008
     1.31
     0.28
     1.28
     0.22Annual 2007
     1.35
     0.66
     1.33
     0.55Annual 2006
     1.25
     0.66
     1.10
     0.58
 B. Plan of Distribution This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. C. Markets On January 31, 1996, our common shares were listed for trading on the TSX Venture Exchange (formerly known as the CDNX, and the Alberta Stock Exchange). Our trading symbol is "NGP", and we are classified by the TSX Venture Exchange as a Tier 2 company. Since July, 2003, our common shares have also been quoted on the OTC Bulletin Board (OTCBB) under the symbol "NGLPF". D. Selling Shareholders This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. E. Dilution This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. F. Expenses of the Issue This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. 85


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86 ITEM 10 Additional Information A. Share Capital This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. B. Memorandum and Articles of Association On November 30, 2005 we adopted new Articles of incorporation in order to conform to the Business Corporations Act, implemented in British Columbia, Canada on March 29, 2004 (the "BCBCA"). With respect to our directors, our Articles provide that a director who is, in any way, directly or indirectly interested in an existing or proposed contract or transaction with NGP, or who holds any office or possesses any property whereby, directly or indirectly, a duty or interest might be created to conflict with his duty or interest as a director, shall declare the nature and extent of his interest in such contract or transaction or the conflict or potential conflict with his duty and interest as a director, as the case may be, in accordance with the provisions of the BCBCA and shall abstain from voting in respect thereof. This prohibition does not apply to: (a)
     any such contract or transaction relating to a loan to NGP, which a director or a specified corporation or a specific firm in which he has an interest has guaranteed or joined in guaranteeing the repayment of the loan or any part of the loan;(b)
     any contract or transaction made or to be made with, or for the benefit of a holding corporation or a subsidiary corporation of which a director is a director;(c)
     any contract or transaction in which a director is, directly or indirectly, interested if all the other directors are also, directly or indirectly, interested in the contract, or transaction;(d)
     determining the remuneration of the directors;(e)
     purchasing and maintaining insurance to cover directors against liability incurred by them as directors; or(f)
     the indemnification of any director by us. Our Articles also provide that the directors may, from time to time: (1) authorize the corporation to borrow money in the manner and amount, on the security, from the sources and upon the terms and conditions as they think fit; (2) issue bonds, debentures and other debt obligations, either outright or as security for any liability or obligation of NGP or any other person; (3) guarantee the repayment of money by another person or the performance of any obligation of another person; and (4) mortgage, charge, whether by way of specific or floating charge, grant a security interest in, or give other security on, the whole or any part of the present and future assets and undertaking of the Company. Variation of these borrowing powers would require an amendment to our Articles which would, in turn, require the approval of our shareholders by way of a special resolution. A special resolution means a resolution approved by not less than 2/3 of the votes cast by our shareholders who, being entitled to do so, vote in person or by proxy at a general meeting of shareholders. If all the shareholders who are entitled to vote at a general meeting consent by a 86


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87 unanimous resolution to the business that was intended to be voted upon at a general meeting, the general meeting will be deemed to be held and the business approved on the date of the unanimous resolution. There is no requirement in our Articles or in the BCBCA requiring retirement or non-retirement of directors under an age limit requirement, nor is there any minimum shareholding required for a director's qualification. Holders of our common shares are entitled to vote at meetings of shareholders, and a special resolution, as described above, is required to effect a change in the rights of shareholders. Holders of common shares are not entitled to pre-emptive rights. Holders of common shares are entitled, rateably, to the remaining property of NGP upon our liquidation, dissolution or winding up, and such holders may receive dividends if, as, and when, declared by our directors. There are no restrictions on the purchase or redemption of common shares by us while there is in arrears in the payment of dividends or sinking fund instalments. There is no liability on the part of any shareholder to further capital calls by us or any provision discriminating against any existing or prospective holder of our securities as a result of such shareholder owning a substantial number of shares. There are no limitations on the rights to own securities, including the rights of non-resident or foreign shareholders to hold or exercise voting rights on the securities imposed by the BCBCA or by our constating documents. We are required to give our registered shareholders not less than 21 days notice of any general meeting held by us unless all such shareholders consent to reduce or waive the period. In addition, we are obliged to fix a record date for a meeting that is no fewer than 30 days or more than 60 days before the meeting. We are also obliged to give notice to registrants and intermediaries who hold shares on behalf of the ultimate beneficial owners with reasonable notice prior to the record date for the meeting. We must then deliver, in bulk, proxy-related materials in amounts specified by the intermediaries. None of our shares owned by registrants or intermediaries may be voted at our general meeting unless all proxy-related materials are delivered to the ultimate beneficial owners of such shares. In order to vote the shares in respect of which a person is the beneficial owner, such beneficial owner must deliver a proxy to us before the deadline for the deposit of proxies stated on the notice. There is no provision in our Articles that would have an effect of delaying, deferring or preventing a change in control, and that would operate only with respect to a merger, acquisition or corporate restructuring involving NGP or any of our subsidiaries. Securities legislation in our home jurisdiction of British Columbia, Canada requires that shareholder ownership must be disclosed once a person owns beneficially or has control or direction over greater than 10% of our issued shares. This threshold is higher than the 5% threshold, at which shareholders must report their share ownership, under U.S. securities legislation. 87


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88 C. Material Contracts Other than contracts entered into during the ordinary course of business, we have entered into the following material contracts during the past two years: 1.
     Second Amendment dated January 13, 2009, to Financial Consulting Agreement between Markus K. Christen and Nevada Geothermal Power Inc., dated January 12, 2007 and July 2nd, 2007 financing engagement letter. (Referenced by Exhibit 4.139)2.
     Purchase Agreement for Blue Claims, NMC 1001318-1001327, NMC1003767-1003783, NMC 1003784-1003787 from Gryphon Gold Corporation to Desert Valley Gold Company dated March 31, 2009 (Referenced by Exhibit 4.142)3.
     Quitclaim Deed from Nevada Eagle Resources LLC (Grantor) to Desert Valley Gold (Grantee) and its successors and assigns forever, all rights, title and interest in the unpatented mining claims in Humboldt County, Nevada as referenced: NMC 1001318-1001327, NMC1003767-1003783, NMC 1003784-1003787, dated April 1, 2009 (Referenced by Exhibit 4.143)4.
     Engineering and construction contract with Industrial Builders for the Geothermal Gathering System for the Geothermal Power Generation Plant, Humboldt County, Nevada dated April 6, 2009. (Referenced by Exhibit 4.144)5.
     Amendment as of April 10, 2009 between Nevada Land and Resource Company, LLC (NLRC) and Nevada Geothermal Power Company (Lessee) for Geothermal Lease #189093 dated March 31, 2003 (Referenced by Exhibit 4.145)6.
     Note Purchase Agreement relating to the US$98.5 Million, 4.14% Senior Secured Notes with John Hancock Life Insurance Company as the Administrative Agent and the Department of Energy as the Guarantor, dated September 2, 2010. (Referenced by Exhibit 4.146)7.
     Letter Agreement for the Joint Development, Financing, Construction, Operation and Maintenance of Crump Geothermal Power Project by Ormat Nevada Inc. and Nevada Geothermal Power Inc. to start construction of a power Project at a size of up to 30MW in 2010 and complete such construction in 2013, dated October 29, 2010. (Referenced by Exhibit 4.147)8.
     Settlement Agreement, Waiver and Mutual Release, between NGP Blue Mountain I LLC (NGP) and Ormat Nevada Inc. (Ormat), dated August 20, 2010, with regards to the Engineering, Procurement and Construction contract NGP entered into an with Ormat for the Completion of the Blue Mountain Faulkner 1 Geothermal Power Plant (the Facility) March 28, 2008. On January 16, 2010, the Facility experienced a shutdown due to overheating in the main ductbank. In the final settlement, Ormat agreed to pay NGP US1,000,000 and provide NGP with one complete Level 1 Turbine and one complete Level 2 Turbine. (Referenced by Exhibit 4.148)9.
     Amended and restated Note Purchase Agreement pursuant to the Note Purchase Agreement (dated August 29, 2008) between NGP Blue Mountain Holdco LLC and TCW Asset Management Company, in which NGP paid down the the aggregate principal amount outstanding on the Notes from $180,000,000 to $87,032,967.70, dated September 2, 2010. (Referenced by Exhibit 4.149)
 88


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89 10.
     Indenture of Trust and Security Agreement between NGP Blue Mountain I LLC and Wilmington Trust Company as Trustee, relating to the Note Purchase Agreement (dated September 2, 2010) between NGP Blue Mountain I LLC, the U.S. Department of Energy and John Hancock life Insurance Company, dated September 2, 2010. (Referenced by Exhibit 4.150)11.
     Assignment of geothermal lease dated June 10, 2010, between NGPC and NGP Crump 1 with regards to the OKeefe Ranch Geothermal Lease Agreement effective August 1, 2005. (Referenced by Exhibit 4.151)12.
     Assignment of geothermal lease dated June 10, 2010, between NGPC and NGP Crump 1 with regards to the LX Ranch Geothermal Lease Agreement effective August 1, 2005(Referenced by Exhibit 4.152)13.
     Assignment of geothermal lease dated May 11, 2010, between NGPC and NGP Crump 1 with regards to the Stabb Ranch Geothermal Lease Agreement effective  August 1, 2005. (Referenced by Exhibit 4.153)14.
     OKeeffe Ranch Geothermal Lease Agreement  Amending Agreement, November 29, 2010, between OKeeffe Ranch and NGP (Crump 1) relating to the OKeeffe Ranch Geothermal Lease Agreement dated August 1, 2005 and the Assignment of geothermal lease dated June 10, 2010. (Referenced by Exhibit 4.154)15.
     LX Ranch Geothermal Lease Agreement  Amending Agreement dated November 29, 2010 between LX Ranch and NGP (Crump 1) relating to the LX Ranch Inc. Geothermal Lease Agreement dated August 1, 2005 and the Assignment of geothermal lease dated June 10, 2010. (Referenced by Exhibit 4.155)16.
     Stabb Geothermal Lease Agreement  Amending Agreement dated November 29, 2010 relating to the Stabb Geothermal Lease Agreement dated August 1, 2005 and the Assignment of geothermal lease dated May 11, 2010. (Referenced by Exhibit 4.156)17.
     Assignment and Assumption of Geothermal Leases dated November 30, 2010 between NGP Crump 1 and Crump Geothermal Company with regards to the OKeefe Ranch Geothermal Lease Agreement, LX Ranch Geothermal Lease Agreement and the Stabb Ranch Geothermal Lease Agreement effective August 1, 2005. (Referenced by Exhibit 4.157)18.
     Limited Liability Company Agreement of Crump Geothermal Company LLC between NGP (Crump 1) and Ormat, Nevada Inc. dated November 30, 2010. (Referenced by Exhibit 4.158)19.
     Assignment and Assumption Agreement dated November 30, 2010 between NGP Crump 1 and Crump Geothermal Company LLC. (Referenced by Exhibit 4.159)20.
     Parent Company Guarantee dated November 29, 2010 by Nevada Geothermal Power Inc, in favour of Crump Geothermal Power Company LLC and Ormat Nevada  Inc. (Referenced by Exhibit 4.160) 89


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90 D. Exchange Controls Exchange Controls There are no governmental laws, decrees or regulations in Canada relating to restrictions on the export or import of capital, or affecting the remittance of interest, dividends or other payments to non-resident holders of our common shares. Any remittances of dividends to United States residents are, however, subject to a 15% withholding tax (5% if the shareholder is a corporation owning at least 10% of our outstanding common shares) pursuant to Article X of the Canada-U.S. Income Tax Convention (1980), as amended (the "Treaty"), and 25% where the Treaty benefits are not available to the shareholder. See "Item 10  Additional Information  E. Taxation" below. Except as provided in the Investment Canada Act (the "Investment Act"), which has provisions that govern the acquisition of a control block of voting shares by non-Canadians of a corporation carrying on a Canadian business, there are no limitations specific to the rights of non-Canadians to hold or vote our common shares under the laws of Canada or the Province of British Columbia or in our charter documents. Our management considers that the following general summary fairly describes those provisions of the Investment Act pertinent to an investment in NGP by a person who is not a Canadian resident (a "non-Canadian"). The Investment Act requires a non-Canadian making an investment that would result in the acquisition of control of the Canadian business to notify the Investment Review Division of Industry Canada, the federal agency created by the Investment Act; or in the case of an acquisition of a Canadian business, the gross value of the assets of which exceeds certain threshold levels or the business activity of which is related to Canada's cultural heritage of national identity, to file an application for review with the Investment Review Division. The notification procedure involves a brief statement of information about the investment on a prescribed form that is required to be filed with Investment Canada by the investor at any time up to 30 days following implementation of the investment. Once the completed notice has been filed, a receipt bearing the certificate date will be issued to the non-Canadian investor. The receipt must advise the investor either that the investment proposal is unconditionally non-reviewable or that the proposal will not be reviewed as long as notice of review is not issued within 21 days of the date certified under the receipt. It is intended that investments requiring only notification will proceed without government intervention unless the investment is in a specific type of business activity related to Canada's cultural heritage and national identity. If an investment is reviewable under the Investment Act, an order for review must be issued within 21 days after the certified date on which notice of investment was received. An application for review in the form prescribed is required to be filed with Investment Canada prior to the investment taking place. Once the application has been filed, a receipt will be issued to the applicant, certifying the date on which the application was received. For incomplete applications, a deficiency notice will be sent to the applicant, and if not cured within 15 days of receipt of application, the application will be deemed to be complete as of the date it was received. Within 45 days after the complete application has been received, the Minister responsible for the Investment Act must notify the potential investor that the Minister is satisfied that the investment is likely to be of net benefit to Canada. If within such 45-day period the Minister is unable to complete the review, the Minister has an additional 30 days to complete the review, unless the 90


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91 applicant agrees to a longer period. Within such additional period, the Minister must advise either that he is satisfied or not satisfied that the investment is likely to be of net benefit to Canada. If the time limits have elapsed, the Minister will be deemed to be satisfied that the investment is likely to be of net benefit to Canada. The investment may not be implemented until the review has been completed and the Minister is satisfied that the investment is likely to be of net benefit to Canada. If the Minister is not satisfied that the investment is likely to be of net benefit to Canada, the non-Canadian must not implement the investment or, if the investment has been implemented, could be penalized by being required to divest him/her/itself of control of the business that is the subject of the investment. To date, the only types of business activities that have been prescribed by regulation as related to Canada's cultural heritage or national identity deal largely with publication, film and music industries. The following investments by non-Canadians are subject to notification under the Investment Act: 1.
     an investment to establish a new Canadian business; and2.
     an investment to acquire control of a Canadian business that is not reviewable pursuant to the Investment Act. The following investments by a non-Canadian are subject to review under the Investment Act: 1.
     direct acquisition of control of Canadian businesses with assets of CDN$5 million or more, unless the acquisition is being made by a World Trade Organization ("WTO") member "country investor" (the United States being a member of the WTO);2.
     direct acquisition of control of Canadian businesses with assets of CDN$299 million or more by a WTO investor (2010 threshold);3.
     indirect acquisition of control of Canadian business with assets of CDN$5 million or more if such assets represent more than 50% of the total value of the assets of the entities, the control of which is being acquired, unless the acquisition is being made by a WTO investor, in which case there is no review;4.
     indirect acquisition of control of Canadian businesses with assets of CDN$50 million or more even if such assets represent less than 50% of the total value of the assets of the entities, the control of which is being acquired, unless the acquisition is being made by a WTO investor, in which case there is no review; and5.
     an investment subject to notification that would not otherwise be reviewable if the Canadian business engages in the activity of publication, distribution or sale of books, magazines, periodicals, newspapers, film or video recordings, audio or video music recordings, or music in print or machine-readable form. Relating to point 2 above, on a date still to be fixed, new regulations under the Investment Act will come into force dramatically increasing the $299-million threshold to $600 million, $800 million and $1 billion over the next six years, with further increases based on a prescribed formula. When the new regulations come into force, the threshold calculation will be based on enterprise value, which has not yet been defined. 91


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92 In addition, under recent amendments to the Investment Canada Act, the Canadian government is now permitted to review any investment by non-Canadians on the basis of national security concerns. No financial threshold applies and the government has up to 50 days following either notification or the filing of an application for review to issue notice of a potential national security review. Therefore, if a proposed transaction that is not otherwise subject to review potentially raises national security concerns, parties should consider filing a notification as early as possible in order to obtain pre-merger clearance (or at least trigger the review period). Generally speaking, an acquisition is direct if it involves the acquisition of control of the Canadian business or of its Canadian parent or grandparent and an acquisition is indirect if it involves the acquisition of control of a non-Canadian parent or grandparent of an entity carrying on the Canadian business. Control may be acquired through the acquisition of actual voting control by the acquisition of voting shares of a Canadian corporation or through the acquisition of substantially all of the assets of the Canadian business. No change of voting control will be deemed to have occurred if less than one-third of the voting control of a Canadian corporation is acquired by an investor. A WTO investor, as defined in the Investment Act, includes an individual who is a national of a member country of the World Trade Organization, or who has the right of permanent residence in relation to that WTO member, a government or government agency of a WTO investor-controlled corporation, limited partnership, trust or joint venture and a corporation, limited partnership, trust or joint venture that is neither WTO-investor controlled or Canadian controlled of which two-thirds of its board of directors, general partners or trustees, as the case may be, or any combination of Canadians and WTO investors. The higher thresholds for WTO investors do not apply if the Canadian business engages in activities in certain sectors such as uranium, financial services, transportation services or communications. The Investment Act specifically exempts certain transactions from either notification or review. Included among this category of transactions is the acquisition of voting shares or other voting interests by any person in the ordinary course of that person's business as a trader or dealer in securities. E. Taxation Material Canadian Federal Income Tax Consequences Management believes that the following general summary accurately describes all material Canadian federal income tax consequences applicable to a holder of common shares of NGP who: (i) is a resident of the United States; (ii) is not and is not deemed to be a resident of Canada; (iii) deals at arms length with and is not affiliated with NGP; (iv) holds the common shares of NGP as capital property; (v) has never been resident in Canada; and who does not use or hold, and is not deemed to use or hold, his common shares of NGP in connection with carrying on or otherwise in connection with a business or permanent establishment (the latter within the 12 month period preceding the date of alienation of any common shares of NGP) in Canada (a "non-resident holder"). In addition, this summary does not apply to a registered nonresident insurer or an authorized foreign bank, both within the meaning of the Income Tax Act(Canada) (the "ITA") and the regulations thereunder (the "Regulations"). 92


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93 This summary is based upon the current provisions of the ITA, the Regulations, the publicly announced administrative and assessing policies of the Canada Revenue Agency to the date hereof, and all specific proposals (the "Tax Proposals") to amend the ITA and the Regulations announced by the Minister of Finance (Canada) prior to the date hereof. This summary assumes that the Tax Proposals will be enacted in their form as of the date hereof. This description, except for the Tax Proposals, does not take into account or anticipate any changes in law, including retroactive amendments, whether by legislative, government or judicial action, nor does it take into account provincial, territorial, or foreign tax considerations which may differ significantly from those discussed herein. This summary is of a general nature only, is not exhaustive of all possible Canadian federal income tax considerations and is not intended to be, nor should it be construed to be, legal or tax advice to any particular non-resident holder. Dividends Dividends paid or credited, or deemed paid or credited, to a non-resident holder on common shares of NGP will be subject to Canadian withholding tax under the ITA. The Canada-US Income Tax Convention (1980), as amended, (the Treaty), will reduce the 25% withholding tax rate under the ITA on such dividends to: (i) 15% where the beneficial owner of the dividends is a resident of the United States and otherwise entitled to Treaty benefits, and (ii) 5% where the beneficial owner of the dividends is a corporation that is a resident of the United States which owns at least 10% of the voting shares of NGP and otherwise entitled to Treaty benefits. Certain look-through rules will apply for non-resident holders that are considered fiscally transparent entities under United States law, in determining whether the beneficial owner is resident in the United States and whether the 10% threshold is met. Not all persons who are residents of the United States will qualify for the benefits under the Treaty. A non-resident holder is advised to consult his own tax advisors in this regard. No dividends have been paid to date by NGP. Dispositions A non-resident holder of common shares of NGP will generally not be subject to tax under the ITA in respect of a capital gain realized upon the disposition or deemed disposition thereof, unless the common shares represent "taxable Canadian property" to the non-resident holder and the non-resident holder is not entitled to Treaty benefits. Provided: (i) the common shares of NGP are listed on a designated stock exchange, as defined under the ITA, (which includes Tiers 1 and 2 of the TSX Venture Exchange) at the time of disposition, and (ii) the value of the common shares of NGP is not derived principally from any combination of real or immovable property situated in Canada, Canadian resource properties, timber resource properties, or options or interests in such property, at any time in the 60 month period that precedes the disposition, the common shares of NGP will generally not constitute taxable Canadian property to a nonresident holder. However, the common shares of NGP may be taxable Canadian property to a non-resident holder if he acquired the common shares pursuant a tax-deferred rollover transaction whereby the non-resident holder substituted common shares of NGP for property that was taxable Canadian property. Where a non-resident holder realizes a capital gain on a disposition of the common shares of NGP that constitute taxable Canadian property, the Treaty relieves the non-resident holder from liability for Canadian income tax on such capital gain unless: (i) the value of the common shares of NGP is derived principally from real property situated in Canada, including the right to 93


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94 explore for or exploit natural resources and rights to amounts computed by reference to production from natural resources; or (ii) the non-resident holder is not considered a resident of the United States under the Treaty, or denied benefits for the Limitation on Benefits provisions under the Treaty as a result of not being a qualying person or otherwise. Note that an individual who is a natural person resident in the United States is a qualifying person for this purpose. A non-resident holder is advised to consult his own tax advisors in this regard. A non-resident holder's capital gain (or capital loss) from a disposition of common shares of NGP that are taxable Canadian property to him, and not exempt from taxation in Canada under the Treaty, will be the amount, if any, by which the proceeds of disposition exceed (or are exceeded by) the aggregate of the adjusted cost base of the shares and reasonable costs of disposition. One-half of a capital gain (the "taxable capital gain") will be included in income, and one-half of a capital loss in a year (the "allowable capital loss") will be deductible from taxable capital gains realized in the same year. The amount by which a non-resident holder's allowable capital loss exceeds his taxable capital gain in a year may generally be deducted from a taxable capital gain realized by the non-resident holder in Canada in the three previous or any subsequent year, subject to the detailed provisions of the ITA. As long as the common shares of NGP are listed on a recognized stock exchange, as defined under the ITA (which includes Tiers 1 and 2 of the TSX Venture Exchange), they will be "excluded property". As such, the non-resident holder will not be required to apply for a certificate of compliance on the disposition of the common shares of NGP, even if they are taxable Canadian property to such holder. A non-resident holder who: (i) disposes of or is deemed to dispose of common shares of NGP that are taxable Canadian property; (ii) has a resulting capital gain that is subject to Part I tax in Canada; and (iii) is not exempt from tax by virtue of the Treaty, will generally be required to file a Canadian income tax return to report the disposition and pay the tax owing within the time and in the manner set out in the ITA. Material United States Federal Income Tax Consequences The following is a summary of United States federal income tax considerations material to a holder of our common shares who is a U.S. Investor (defined below). The summary is of a general nature only and is not exhaustive of all possible income tax consequences applicable to U.S. Investors and does not address the tax consequences of U.S. Investors subject to special provisions of federal income tax law. This summary is based on the Internal Revenue Code of 1986, as amended (the "Code"), Treasury regulations, court decisions and current administrative rulings and pronouncements of the United States Internal Revenue Service ("IRS") that are currently applicable, all of which are subject to change, possibly with retroactive effect. There can be no assurance that future changes in applicable law or administrative and judicial interpretations thereof will not adversely affect the tax consequences discussed herein. Since the United States federal income and withholding tax treatment may vary depending upon your particular situation, you may be subject to special rules not discussed below. Special rules will apply, for example, if you are: 
     an insurance company;
  a tax-exempt organization; 
    a financial instituation;
    a person subject to the alternative minimum tax; 94


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95 
  a person who is a broker-dealer in securities;
  an S corporation;
  an expatriate subject to Section 877 of the Code;
  an owner of, directly, indirectly or by attribution, 10% or more of the outstanding common shares;
  an owner holding common shares as part of a hedge, straddle, synthetic security or conversion transaction; or
  a partnership or other entity classified as a partnership for U.S. federal income tax purposes. In addition, this summary is generally limited to persons holding common shares as "capital assets" within the meaning of Section 1221 of the Code, and whose functional currency is the U.S. dollar. The discussion below also does not address the effect of any United States state or local tax law or foreign tax law. As used herein, a U.S. Investor is a beneficial owner of common shares that is, for U.S. federal income tax purposes: (i) a citizen or resident of the United States; (ii) a corporation, or other entity taxable as a corporation, created or organized under the laws of the United States or any political subdivision thereof; (iii) an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source; or (iv) a trust that (1) is subject to the primary supervision of a court within the United States and the control of one or more United States persons or (2) has a valid election in effect under applicable Treasury regulations. Distributions Subject to the discussion below of the consequences of our being treated as a passive foreign investment company (PFIC) for United States federal income tax purposes, the gross amount of a distribution, including any foreign withholding taxes, with respect to your common shares will be treated as a taxable dividend to the extent of our current and accumulated earnings and profits, computed in accordance with United States federal income tax principles. For taxable years beginning before January 1, 2011, dividends received by U.S. Investors that are individuals, estates or trusts from a qualified foreign corporation as defined in Section 1(h)(11) of the Code, generally are taxed at the same preferential tax rates applicable to long-term capital gains provided (1) certain holding period requirements are satisfied, (2) we are eligible for the benefits of the income tax treaty or the securities exchange requirement is met, and (3) we are not, for the taxable year in which the dividend was paid, or in the preceding taxable year, a PFIC. As discussed below, we believe we were not a PFIC for the taxable year ended June 30, 2010. U.S. Investors are strongly urged to consult their own tax advisors as to the applicability of the lower capital gains rate to dividends received with respect to the common shares. Distributions in excess of our current or accumulated earnings and profits will be applied against and will reduce your tax basis in your common shares and, to the extent in excess of such tax basis, will be treated as gain from a sale or exchange of such common shares. You should be aware that we do not intend to calculate our earnings and profits for United States federal income tax purposes and, unless we make such calculations, you should assume that any distributions with respect to common shares generally will be treated as a dividend, even if that distribution would otherwise be treated as a return of capital or as capital gain pursuant to the rules described above. 95


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96 If you are a corporation, you will not be allowed a deduction for dividends received in respect of distributions on common shares, which is generally available for dividends paid by U.S. corporations. A dividend distribution will be treated as foreign source income and will generally constitute "passive category income" but could, in the case of certain U.S. Investors, constitute "general category income." The rules relating to the determination of the foreign tax credit, or deduction in lieu of the foreign tax credit, are complex and you should consult your own tax advisors with respect to those rules. Dispositions of Common Shares Subject to the discussion below of the consequences of being treated as a PFIC, gain or loss realized by a U.S. Investor on the sale or other disposition of common shares will be subject to United States federal income tax as capital gain or loss in an amount equal to the difference between such U.S. Investors basis in the common shares and the amount realized on the disposition. In general, such capital gain or loss will be long-term capital gain or loss if the U.S. Investor has held the common shares for more than one year at the time of the sale or exchange. If you are an individual, such realized long-term capital gain is generally subject to a reduced rate of United States federal income tax. Limitations may apply to your ability to offset capital losses against ordinary income. Subject to the PFIC rules discussed below, in general, gain from a sale, exchange or other disposition of the common shares by a U.S. Investor will be treated as U.S. source income for foreign tax credit purposes. (See discussion at Foreign Tax Credit below). Therefore, the use of foreign tax credits relating to any foreign taxes imposed upon such sale may be limited. You are strongly urged to consult your own tax advisors as to the availability of tax credits for any foreign taxes withheld on the sale of common shares. Foreign Tax Credit A U.S. Investor that pays (whether directly or through withholding) foreign income tax in connection with the ownership or disposition of common shares may be entitled, at the election of such U.S. Investor, to receive either a deduction or a credit for such foreign income tax paid. Generally, a credit will reduce a U.S. Investors U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Investor's income subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Investor during a year. Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Investors U.S. federal income tax liability that such U.S. Investors "foreign source" taxable income bears to such U.S. Investors worldwide taxable income. In applying this limitation, a U.S. Investors various items of income and deduction must be classified, under complex rules, as either "foreign source" or "U.S. source." Generally, dividends paid by a foreign corporation should be treated as foreign source for this purpose, while gains recognized on the sale of stock of a foreign corporation by a United States person (as defined in section 7701(a) (30) of the Code) should be treated as U.S. source for this purpose. 96


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97 However, the amount of a distribution with respect to the common shares that is treated as a "dividend" may be lower for U.S. federal income tax purposes than it is for Canadian federal income tax purposes, resulting in a reduced foreign tax credit allowance to a U.S. Investor. In addition, this limitation is calculated separately with respect to specific categories of income. Dividends will be treated either as "passive income" or "general income". In addition, special foreign tax credit rules apply to a U.S. Investor that receives "qualified dividend income" that is subject to reduced U.S. federal income tax rates. The rules relating to the determination of the foreign tax credit, or deduction in lieu of the foreign tax credit, are complex and you should consult your own tax advisors with respect to those rules. Passive Foreign Investment Company The Company believes it was not a PFIC for United States federal income tax purposes for its taxable year ended June 30, 2010. However, as noted in the Companys annual report for its taxable year ended June 30, 2009, the Company believes that it was a PFIC for the taxable year ended June 30, 2009 and may be treated as a PFIC for its future taxable years. This conclusion is a factual determination made annually and thus subject to change. Based on the composition of its income, assets and operations, the Company believes it will not be treated as a PFIC for the fiscal year ended June 30, 2010. However, because the determination of whether the Company is a PFIC for a taxable year is made after the close of the taxable year based on actual income and assets values during such taxable year, no assurances can be given that the Company will not be a PFIC for the fiscal year ending June 30, 2011 or any future taxable year. U.S. Investors should consult their tax advisors regarding the tax consequences of the Company being a PFIC for the fiscal year ended June 30, 2010 the fiscal year ending June 30, 2011 as well as any future year. We will be a PFIC with respect to a U.S. Investor if, for any taxable year in which such U.S. Investor held our common shares, either (i) at least 75% of our gross income for the taxable year is passive income, or (ii) at least 50% of our assets are attributable to assets that produce or are held for the production of passive income. In each case, we must take into account a pro rata share of the income and the assets of any company in which we own, directly or indirectly, 25% or more of the stock by value (the "look-through" rules). Passive income generally includes dividends, interest, royalties, rents (other than rents and royalties derived from the active conduct of a trade or business and not derived from a related person), annuities, and gains from assets that produce passive income. In addition, if we are a PFIC and own shares of another subsidiary that is a PFIC (a lower-tier PFIC), under certain indirect ownership rules, a disposition of the shares of such other lower-tier PFIC or a distribution received from such other lower-tier PFIC generally will be treated as an indirect disposition by a U.S. Investor or an indirect distribution received by a U.S. Investor, subject to the rules of Section 1291 of the Code discussed below. The determination of whether we will be a PFIC for each taxable year will depend, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations. In addition, whether we will be a PFIC for each taxable year will depend on our assets and income over the course of each such taxable year and, as a result, cannot be predicted with certainty at this time. Accordingly, there can be no assurance that the IRS will not challenge the determination made by us concerning our PFIC status. 97


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98 Default PFIC Rules Under Section 1291 of the Code If we are a PFIC, the U.S. federal income tax consequences to a U.S. Investor of the acquisition, ownership, and disposition of the common shares will depend on whether such U.S. Investor makes an election to treat the Company as a qualified electing fund or QEF under Section 1295 of the Code (a QEF Election) or a mark-to-market election under Section 1296 of the Code (a Mark-to-Market Election). A U.S. Investor that does not make either a QEF Election or a Mark-to-Market Election is referred to herein as a Non-Electing U.S. Investor. If we are determined to be a PFIC for any taxable year during which a Non-Electing U.S. Investor holds common shares, the U.S. Investor will be subject to special tax rules under Section 1291 of the Code with respect to: 
     any "excess distribution" that the U.S. Investor receives or is deemed to receive on common shares. Distributions the Non-Electing U.S. Investor receives in a taxable year (or distributions by a lower-tier PFIC to its shareholder that are deemed to be received by a U.S. Investor) that are greater than 125% of the average annual distributions the U.S. Investor received or is deemed to have received during the shorter of the three preceding taxable years or the Non-Electing U.S. Investors holding period for the common shares will be treated as an excess distribution; and
  any gain the U.S. Investor realizes from a sale or other disposition (including a pledge) of the common shares (including an indirect disposition of shares of a lower-tier PFIC). Under certain proposed Treasury regulations, a "disposition" for this purpose may include, under certain circumstances, transfers at death, gifts, pledges, transfers pursuant to tax-deferred reorganizations and other transactions with respect to which gain ordinarily would not be recognized. Under certain circumstances, the adjustment generally made to the tax basis of property held by a decedent may not apply to the tax basis of common shares if a qualified electing fund (QEF) election was not in effect for the deceased United States person's entire holding period. Any loss recognized by a U.S. Investor on the disposition of common shares will not be recognized unless the loss is otherwise recognized under the Code. Under these special tax rules: 
     the excess distribution or gain recognized (or deemed recognized) will be allocated rateably over your holding period for the common shares;
  the amount allocated to the taxable year of disposition or deemed disposition, and any taxable year prior to the first taxable year in which we were a PFIC, will be treated as ordinary income; and
  the amount allocated to each other taxable year will be subject to tax at the highest tax rate in effect for such taxable year of the U.S. Investor and the interest charge generally applicable to underpayments of tax will be imposed on the resulting tax attributable to each such year. The tax liability for amounts allocated to years prior to the year of disposition or excess distribution cannot be offset by any net operating losses, and gains (but not losses) realized on the sale of the common shares cannot be treated as capital, even if the U.S. Investor holds the common shares as capital assets. 98


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99 We will continue to be treated as a PFIC with respect to any common shares held by a Non-Electing U.S. Investor if such common shares were held while we were treated as a PFIC, or will hold our common shares for any other taxable year in which we are a PFIC, regardless of whether we cease to be a PFIC in one or more subsequent years. However, if we cease to be a PFIC, a Non-Electing U.S. Investor may avoid some of the adverse effects of the PFIC regime by making a deemed sale election with respect to such common shares. If a U.S. Investor makes this deemed sale election, the U.S. Investor will be deemed to have sold, at fair market value, such common shares (and shares of our PFIC subsidiaries, if any, that the U.S. Investor is deemed to own) on the last day of the last taxable year for which we were a PFIC. A U.S. Investor generally would be subject to the unfavorable PFIC rules described above in respect of any gain realized on such deemed sale, but as long as we are not a PFIC in future years, a U.S. Investor would not be subject to the PFIC rules in those future years. QEF Election A U.S. Investor of a PFIC may avoid taxation under the excess distribution and gain rules of Section 1291 discussed above by making a QEF election to include the U.S. Investors share of our income on a current basis. A U.S. Investor that makes a QEF Election will be subject to U.S. federal income tax on such U.S. Investors pro rata share of (a) the net capital gain of the Company, which will be taxed as long-term capital gain to such U.S. Investor, and (b) and the ordinary earnings of the Company, which will be taxed as ordinary income to such U.S. Investor. A U.S. Investor that makes a QEF Election will be subject to U.S. federal income tax on such amounts for each taxable year in which we are a PFIC, regardless of whether such amounts are actually distributed to such U.S. Investor. However, a U.S. Investor that makes a QEF Election may, subject to certain limitations, elect to defer payment of current U.S. federal income tax on such amounts, subject to an interest charge. A U.S. Investor that makes a QEF Election generally (a) may receive a tax-free distribution from the Company to the extent that such distribution represents earnings and profits that were previously included in income by the U.S. Investor because of such QEF Election and (b) will adjust such U.S. Investors tax basis in the common shares to reflect the amount included in income or allowed as a tax-free distribution because of such QEF Election. In addition, a U.S. Investor that makes a QEF Election generally will recognize capital gain or loss on the sale or other taxable disposition of common shares. The procedure for making a QEF Election, and the U.S. federal income tax consequences of making a QEF Election, will depend on whether such QEF Election is timely. A QEF Election will be treated as timely if such QEF Election is made for the first year in the U.S. Investors holding period for the common shares in which the Company was a PFIC. A U.S. Investor may make a timely QEF Election by filing the appropriate QEF Election documents at the time such U.S. Investor files a timely U.S. federal income tax return for such first year. In order for the QEF Election to apply to the Company and each lower-tier PFIC, a separate QEF Election must be made for each entity. A QEF Election will apply to the taxable year for which such QEF Election is made and to all subsequent taxable years, unless such QEF Election is invalidated or terminated or the IRS consents to revocation of such QEF Election. If a U.S. Investor makes a QEF Election and, in a subsequent taxable year, the Company ceases to be a PFIC, the QEF Election will remain in effect (although it will not be applicable) during those taxable years in which the Company is not 99


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100 a PFIC. Accordingly, if the Company becomes a PFIC in another subsequent taxable year, the QEF Election will be effective and the U.S. Investor will be subject to the QEF rules described above during any such subsequent taxable year in which the Company qualifies as a PFIC. However, a U.S. Investor may make a QEF election only if we, as a PFIC furnish the shareholder annually with certain tax information. However, in part because we do not plan on keeping a set of U.S. tax accounting books, we do not intend to generate, or share with you, the information that you might need to properly complete the IRS Form required to be filed in connection with a QEF. Each U.S. Investor should consult his or her own financial advisor, legal counsel, or accountant regarding the availability of, and procedure for making, a QEF Election. Mark-to-Market Election The Mark-to-Market Election is available only for marketable stock, which is stock that is traded in other than de minimisquantities on at least 15 days during each calendar quarter on a qualified exchange or other market. Under applicable U.S. Treasury regulations, a qualified exchange includes a foreign exchange that is regulated by a governmental authority in the jurisdiction in which the exchange is located and in respect of which certain other requirements are met. The Mark-to-Market Election would likely not be available for any subsidiary that is a PFIC. You should consult your own tax advisers as to whether the common shares would qualify for the Mark-to-Market Election. The PFIC rules are complex, and each U.S. Investor should consult its own financial advisor, legal counsel, or accountant regarding the PFIC rules and how the PFIC rules may affect the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares. Receipt of Canadian Currency The amount paid in Canadian dollars to a U.S. Investor on the sale, exchange or other taxable disposition of the common shares will be translated to the U.S. dollar value of the payment received. If the common shares are treated as traded on an established securities market and you are either a cash basis taxpayer or an accrual basis taxpayer who has made a special election (which must be applied consistently from year to year and cannot be changed without the consent of the IRS), you will determine the U.S. dollar value of the amount realized in a foreign currency by translating the amount received at the spot rate of exchange on the settlement date of the sale. Taxable dividends with respect to common shares that are paid in Canadian dollars will be included in the gross income of a U.S. Investor as translated into U.S. dollars calculated by reference to the exchange rate prevailing on the date the dividend is included in income, regardless of whether the Canadian dollars are converted into U.S. dollars at that time. Any U.S. Holder who receives payment in Canadian dollars and engages in a subsequent conversion or other disposition of the Canadian dollars may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes. Each U.S. Investor should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of Canadian dollars. 100


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101 U.S. Information Reporting and Backup Withholding In general, information reporting requirements will apply to dividends in respect of our common shares, or the proceeds received on the sale, exchange or redemption of our common shares paid within the United States (and, in certain cases, outside the United States) to U.S. Investors other than certain exempt recipients, and backup withholding tax may apply to such amounts if the U.S. Investor (a) fails to furnish such U.S. Investor's correct U.S. taxpayer identification number (generally on Form W-9); (b) furnishes an incorrect U.S. taxpayer identification number; (c) is notified by the IRS that such U.S. Investor has previously failed to properly report items subject to backup-withholding tax; or (d) fails to certify, under penalty of perjury, that such U.S. Investor has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Investor that it is subject to backup-withholding tax. Backup withholding is not an additional U.S. federal income tax. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Investor's U.S. federal income tax liability, if any, or will be refunded to the extent it exceeds such liability, if such U.S. Investor timely furnishes required information to the IRS. A U.S. Investor that does not provide a correct U.S. taxpayer identification number may be subject to penalties imposed by the IRS. Each U.S. Investor should consult its own U.S. tax advisor regarding the information reporting and backup withholding tax rules. A U.S. Investor who holds common shares in any year in which we are determined to be a PFIC would be required to file an annual information report with the IRS regarding distributions received on common shares and any gain recognized in the disposition of common shares with respect to the Company and each lower-tier PFIC. New Legislation For taxable years beginning after March 18, 2010, new legislation requires certain U.S. Investors who are individuals to report information relating to an interest in our common shares, subject to certain exceptions (including an exception for common shares held in accounts maintained by certain financial institutions). U.S. Investors should consult their tax advisors regarding the effect, if any, of this legislation on their ownership and disposition of our common shares. ALL INVESTORS ARE ADVISED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE SPECIFIC TAX CONSEQUENCES OF PURCHASING THE COMMON SHARES OF OUR COMPANY. F. Dividends and Paying Agents Not Applicable. G. Statements by Experts Not Applicable. H. Documents on Display We file financial statements and other information with Canadian securities regulatory authorities electronically through the System for Electronic Document Analysis and Retrieval (SEDAR) which can be viewed at www.sedar.com. 101


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102 We file Annual Reports and other information with the United States Securities and Exchange Commission. These documents are filed electronically at the Commission's Edgar website. You may read and copy any document that we file at the Commissions Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by accessing the Commission's website (http://www.sec.gov). Please call the Commission at 1-800-SEC-0330 for more information about the Public Reference Room. Any exhibits and documents referred to in this Annual Report may be inspected at our head office, Suite 900-409 Granville Street, Vancouver, British Columbia, by making an appointment during normal business hours. I. Subsidiary Information There is no information relating to our subsidiaries that must be provided in Canada and that is not otherwise called for by the body of generally accepted accounting principles used in preparing our financial statements. ITEM 11 Quantitative and Qualitative Disclosures About Market Risk Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of the changes in market prices. Currency risk The operating results and financial position of the Company are reported in US dollars. The Company operates in Canada and the United States. The Companys US operations functional currency is the US dollar, and these operations are therefore subject to risk arising from future transactions as well as recognized assets and liabilities which are denominated in currencies other than US dollars. The Companys Canadian operations functional currency is the Canadian dollar and these operations are therefore subject to risk arising from future transactions as well as recognized assets and liabilities which are denominated in currencies other than Canadian dollars. The sensitivity analysis below provides details on the effect of a reasonably possible change in exchange rates on the net income and other comprehensive income of the Company. The effect on other comprehensive income arises from the translation of the financial statements of the Companys Canadian operations into US dollars. Carrying amount
     
     
     5% increase
     
     
     5% decreaseof asset (liability)
     
     
     in value
     
     
     in valueJune 30, 2010
     
     
     of CAD
     
     
     of CADEffect on net incomeCash and cash equivalents denominated in USD in Canadian Operations
     $
     804,190
     
     $
     (40,518
     )
     $
     40,518Effect on other comprehensive incomeCash and cash equivalents denominated in CAD
     
     989,575
     
     
     52,052
     
     
     (47,097
     )Amounts receivable denominated in CAD
     
     25,056
     
     
     1,318
     
     
     (1,192
     )Accounts payable and accrued liabilities
     
     (650,508
     )
     
     (34,217
     )
     
     30,960$
     1,168,313
     
     $
     (21,365
     )
     $
     23,189
 102


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103 Cash flow and fair value interest rate risk Financial instruments with floating rates are subject to cash flow interest rate risk; financial instruments with fixed rates are subject to fair value interest rate risk. The Company invests its cash and cash equivalents in certificates of deposit and guaranteed investment certificates and bankers acceptances with terms of 90 days or less in order to maintain liquidity while achieving a satisfactory return for shareholders. A balance is maintained between fixed and floating rate instruments. The long-term liability has a fixed interest rate of 14% and is subject to fair value interest rate risk. The instrument is carried at amortized cost, and changes in market interest rates will not affect income. Carrying amountof asset (liability)
     
     
     1% increase
     
     
     1% decreaseJune 30, 2010
     
     
     in interest rates
     
     
     in interest ratesEffect on net incomeCash and cash equivalents with floating rates
     $
     5,468,231
     
     $
     109,685
     
     $
     (71,850
     )Cash settled option
     
     (2,722,396
     )
     
     112,721
     
     
     (191,590
     )$
     2,745,835
     
     $
     222,406
     
     $
     (263,440
     )
 Other price risk Other price risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices, such as commodity or equity prices. The Company is subject to other price risk arising from a number of balances and transactions. In the first place, the fair value of the marketable securities is affected by equity prices. Carrying amountof asset (liability)
     
     
     50% increase in
     
     
     50% decrease inJune 30, 2010
     
     
     share price
     
     
     share priceEffect on other comprehensive incomeMarketable securities
     $
     71,388
     
     $
     35,694
     
     $
     (35,694
     )
 In addition the fair value of the cash settled option is affected by estimated market prices for electricity beyond the contracted period. Carrying amount
     
     
     5% increase
     
     
     5% decreaseof asset (liability)
     
     
     in electricity
     
     
     in electricityJune 30, 2010
     
     
     prices
     
     
     pricesEffect on net incomeCash settled option
     $
     (2,722,396
     )
     $
     (352,156
     )
     $
     358,223
 Revenue, from excess electricity produced, is also influenced by market prices for electricity. A reasonable possible change in market prices for electricity would not have had a material impact on the Companys financial statements. 103


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104 Credit Risk The Company has limited exposure to credit risk, since credit risk primarily arises from the Companys cash and cash equivalents, restricted cash and accounts receivable. The risk exposure is limited to the carrying amounts of these items at the balance sheet date. Cash and cash equivalents are held as cash deposits and invested in bankers acceptance, guaranteed investment certificates and certificates of deposit with various maturity dates. Restricted cash consists of certificates of deposit held with the Bank of the West and Wilmington Trust. The Company periodically assesses the quality of its investments and is satisfied with the credit ratings of its banks and their certificates of deposit and guaranteed investment certificates. Accounts receivable consist of amounts due from NVE for electricity, insurance proceeds and sales goods and services tax recoverable. To reduce credit risk, the Company regularly reviews the collectability of its amounts receivable and establishes an allowance based on its best estimate of potentially uncollectable amounts, if required. There were no amounts past due as at year-end. ITEM 12 Description of Securities Other Than Equity Securities This Form 20-F is being filed as an Annual Report under the Exchange Act and, as such, there is no requirement to provide any information under this Item. PART II ITEM 13 Defaults, Dividend Arrearages and Delinquencies At June 30, 2010 the Company was not in compliance with its loan agreement with TCW, principally as a result of project capital costs. By September 30, 2010 the loan was paid down to approximately $86 million and, after issuing 4.5 million warrants exercisable at CAD $1.50, TCW waived the non compliance. The Company is in compliance with its loan agreements as of the date of this report. The Company expects to successfully complete additional drilling, increase Blue Mountain power production and raise additional funds with which to pay TCW down to a maximum of $70 million. If the Company is not successful it will not remain in compliance with the TCW debt service coverage ratio and TCW may elect to act on its security, which could result in the loss of the Blue Mountain equity. ITEM 14 Material Modifications to the Rights of Security Holders and Use of Proceeds Neither we nor, to the best of our knowledge, anyone else has modified materially or qualified the rights evidenced by any class of registered securities. ITEM 15 Controls and Procedures Disclosure Controls and Procedures Our disclosure controls and procedures are designed to ensure that information required to be disclosed in our reports filed under Canadian and U.S. securities regulations is recorded, processed, summarized and reported within the time periods specified and is accumulated and 104


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105 communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. An evaluation was carried out under the supervision of, and with the participation of, our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as such term is defined in the Exchange Act, as amended, Rules 13a-15(e) and 15d-15(e)) as of June 30, 2009. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2010. Managements Annual Report on Internal Control over Financial Reporting Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Securities Exchange Act Rules 13a-15(f) and 15d to 15(f). A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, management conducted an evaluation of the effectiveness of our internal control over financial reporting, as of June 30, 2010, based on a framework set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company maintained, in all material respects, effective internal controls over financial reporting as of June 30, 2010. This annual report includes an attestation report of the companys registered public accounting firm, Deloitte and Touche LLC, regarding internal control over financial reporting. Changes in Internal Control over Financial Reporting As the Company has grown and established revenue producing operations there have been changes in our internal control over financial reporting during the period covered by the annual report, being the fiscal year ended June 30, 2010, that have materially affected, and are 105


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106 reasonably likely to materially affect our internal control over financial reporting. In addition to taking steps to increase the efficiency of its internal controls to ensure continued accuracy and timeliness of the Companys financial reporting the Company has hired another qualified accountant as Director of Finance and the position has increasingly segregated duties. In addition, the Company has increased monthly reporting requirements reconciling a variety of accounts and these improvements have and will improve internal control. ITEM 16A Audit Committee Financial Expert Our Board has determined that it has more than one audit committee financial expert serving on its audit committee. Domenic J. Falcone, CPA, is our "audit committee chair" and an audit committee financial expert as defined by the rules of the Commission. Mr. Falcone possesses the educational and professional qualifications and experience to qualify as such. In addition to Mr. Falcone's experience, we also believe that all members of the audit committee and of our Board are collectively capable of analyzing and evaluating our financial statements and understanding internal controls and procedures for financial reporting. ITEM 16B Code of Ethics Code of Ethics Effective August 23, 2005, our Board adopted a Policy Manual that includes a Code of Business Conduct and Ethics that applies to, among other persons, our chief executive officer (being our principal executive officer) and our chief financial officer (being our principal financial and accounting officer), as well as persons performing similar functions. As adopted, our Code of Business Conduct and Ethics sets forth written standards that are designed to deter wrongdoing and to promote: (1)
     honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;(2)
     full, fair, accurate, timely, and understandable disclosure in reports and documents that we file with, or submit to, the Commission and in other public communications made by us;(3)
     compliance with applicable governmental laws, rules and regulations;(4)
     the prompt internal reporting of violations of the Code of Business Conduct and Ethics to an appropriate person or persons identified in the Code of Business Conduct and Ethics; and(5)
     accountability for adherence to the Code of Business Conduct and Ethics. Our Code of Business Conduct and Ethics requires, among other things, that all of our personnel shall be accorded full access to our chief executive and chief financial officers with respect to any matter which may arise relating to the Code of Business Conduct and Ethics. Further, all of our Company's personnel are to be accorded full access to our Company's Board if any such matter involves an alleged breach of the Code of Business Conduct and Ethics by our president or chief financial officer. 106


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107 In addition, our Code of Business Conduct and Ethics emphasizes that all employees, and particularly managers and/or supervisors, have a responsibility for maintaining financial integrity within our Company, consistent with generally accepted accounting principles, and federal, provincial and state securities laws. Any employee who becomes aware of any incidents involving financial or accounting manipulation or other irregularities, whether by witnessing the incident or being told of it, must report it to his or her immediate supervisor or to our Company's president or secretary. If the incident involves an alleged breach of the Code of Business Conduct and Ethics by the president or secretary, the incident must be reported to any member of our Board. Any failure to report such inappropriate or irregular conduct of others is to be treated as a severe disciplinary matter. It is against our Company policy to retaliate against any individual who reports in good faith the violation or potential violation of our Company's Code of Business Conduct and Ethics by another. We undertake to provide a copy of our Code of Business Conduct and Ethics to any person, without charge, upon request in writing to our secretary. Alternatively, you may view a copy of our Code of Business Conduct and Ethics by visiting our web site located at www.nevadageothermal.com. ITEM 16C Principal Accountant Fees and Services Our audit committee pre-approves all services provided by our independent auditors. All of the services and fees described below were reviewed and pre-approved by our audit committee. Our audit committee may delegate to one or more designated members of the audit committee the authority to grant pre-approvals. The decisions of any audit committee member to whom authority is delegated to pre-approve a service must be presented to the full audit committee at its next scheduled meeting. Our auditors, Deloitte & Touche LLP, were first appointed by the audit committee and the directors of the Company on March 9, 2009 and replaced Morgan & Company, Chartered Accountants as auditors. The audit committee has considered the nature and amount of the following fees billed by Deloitte & Touche LLP, and believes that the provision of the services for activities unrelated to the audit is compatible with maintaining Deloitte & Touche LLP, independence. Audit Fees The aggregate fees expected to be billed by Deloitte & Touche LLP, for professional services rendered for the audit of our annual financial statements included in this Annual Report for the fiscal year ended June 30, 2010 was CDN $153,000 (2009: CDN $157,400). These services also include those that are normally provided in connection with statutory and regulatory filings or engagements for those fiscal years. The aggregate fees billed by Morgan & Company, Chartered Accountants, for professional services rendered for the audit of our annual financial statements included in this Annual Report for the fiscal years ended June 30, 2008 and 2007 were $110,000 and $53,000, respectively. These services also include those that are normally provided in connection with statutory and regulatory filings or engagements for those fiscal years. 107


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108 Audit Related Fees For the fiscal year ended June 30, 2010, the aggregate fees billed for assurance and related services by Deloitte & Touche LLP, relating to our financial statements and which are not reported under the caption "Audit Fees" above, were CDN $79,659 (2009: CDN $10,016). Tax Fees For the fiscal year ended June 30, 2010, the aggregate fees billed for tax compliance, tax advice and tax planning by Deloitte & Touche LLP were CDN $79,374. For the fiscal year ended June 30, 2008, the aggregate fees billed for tax compliance, tax advice and tax planning by Morgan & Company, Chartered Accountants, were $2,500. All Other Fees For the fiscal year ended June 30, 2010, the aggregate fees billed by Deloitte & Touche LLP, Chartered Accountants, for other non-audit professional services, other than those services listed above, totalled CDN $304,126 (2009: CDN $104,540). ITEM 16D. Exemption from the Listing Standards for Audit Committees Not Applicable. ITEM 16E Purchases of Equity Securities by the Issuer and Affiliated Purchasers Not Applicable. ITEM 16F Change in Registrants Certifying Accountant Our auditors, Deloitte & Touche LLP, were first appointed by the audit committee and the directors of the Company on March 9, 2009 and replaced Morgan & Company, Chartered Accountants as auditors. Deloitte & Touche were responsible for the audit of the annual financial statements for the years ended June 30, 2009 and 2010, Morgan & Company were responsible for the audit of the annual financial statements for the year ended June 30, 2008. ITEM 16G Corporate Governance Not Applicable. PART III ITEM 17 Financial Statements The linked financial statements were prepared in accordance with Canadian GAAP and are expressed in US dollars. Such financial statements have been reconciled to U.S. GAAP (see Note 22 therein). For a history of exchange rates in effect for Canadian dollars as against U.S. dollars, see Page 9 of this Annual Report. 108


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109 The financial statements are filed as part of the Annual Report: 
     Consolidated financial statements for the year ended June 30, 2010.
  Consolidated financial statements for the year ended June 30, 2009. ITEM 18 Financial Statements See Exhibit 9.1 and 9.2 109


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ITEM 19 Exhibits The following exhibits are being filed as part of this Annual Report, or are incorporated by reference where indicated: EXHIBITS filed on FTP Site
     Description of Exhibit1.Articles of Incorporation and By-laws:1.1
     Certificate of Incorporation and Articles of Blue Desert Mining Inc. dated April 13, 1995. (1)1.2
     Special Resolution and Altered Memorandum filed October 3, 1995. (1)1.3
     Certificate of Name Change from "Blue Desert Mining Inc." to "Canada Fluorspar Inc." dated May 25, 2000. (1)1.4
     Certificate of Name Change from "Canada Fluorspar Inc." to "Continental Ridge Resources Inc." dated February 5, 2001. (1)1.5
     Certificate of Name Change from "Continental Ridge Resources Inc." to "Nevada Geothermal Power Inc." dated May 13, 2003. (1)1.6
     Articles adopted by Nevada Geothermal Power Inc. on November 30, 2005. (1)1.7
     Notice of Articles dated January 25, 2006. (1)2. Instruments Defining Rights of Security Holders2.1
     Specimen Certificate of Common Stock.(1)2.2
     Incentive Stock Option Plan adopted November 30, 2005 (Also listed under Exhibit 4.33).(1)2.3
     Form of Option Agreement.(1)2.4
     Warrant issued to Susan Power for 77,000 common shares dated June 2005.(1)2.5
     Form of Warrant dated April 21, 2006, with an exercise price of Canadian Dollars $1.40.(1)


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2.6
     Form of agent's compensation option dated April 28, 2006 for the purchase of underwriting units, comprised of our common shares and share purchase warrants, at a price of $0.90 per underwriting unit until April 28, 2008.(1)2.7
     Form of Compensation Option Certificate with Clarus Securities Inc. in reference to Underwriting agreement dated April 23, 2008 with Dundee Securities Corporation. (3)2.8
     Form of Compensation Option Certificate with Jacob & Company Securities in reference to Underwriting agreement dated April 23, 2008 with Dundee Securities Corporation for a private placement. (4)2.9
     Form of Compensation Option Certificate with Dundee Securities Corporation in reference to Underwriting agreement dated April 23, 2008 with Dundee Securities Corporation. (3)2.10
     Shareholders Rights Plan Agreement between Nevada Geothermal Power Inc. and Computershare Investor Services Inc. Approved by the Directors on November 25, 2008, Effective as of December 4, 2008 (4)4. Material Contracts4.1
     Geothermal Lease No. 187556 between Burlington Northern Santa Fe (formerly The Atchison Topeka and Santa Fe Railway Company) and Power Company regarding Blue Mountain, dated October 19, 1993, as amended March 31, 2003 and November 1, 2005.(1)4.2
     Offer to Lease and Lease for Geothermal Resources Lease No. 58196 between the Federal Bureau of Land Management and Noramex Corp. regarding Blue Mountain, effective date of April 1, 1994.(1)4.3
     Grant Bargain and Sale Deed between Nevada Land & Resource Company, LLC and Delong Ranches, Inc., dated September 10, 1999.(1)4.4
     Option Agreement between Continental Ridge Resources Inc. and Blue Mountain Power Company for Blue Mountain Geothermal Project, Humboldt County, Nevada, dated June 19, 2001.(1)4.5
     Offer to Lease and Lease for Geothermal Resources Lease No. 74855 between the Federal Bureau of Land Management and Sierra Nevada Geothermal, Inc., effective date of June 1, 2002.(1)4.6
     Option Amendment Agreement between Continental Ridge Resources Inc. and Blue Mountain Power Company for Blue Mountain Geothermal Project, Humboldt County, Nevada, dated August 7, 2002.(1)
  111


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4.7
     Option Amendment Agreement between Continental Ridge Resources Inc. and Blue Mountain Power Company for Blue Mountain Geothermal Project, Humboldt County, Nevada, dated November 12, 2002.(1)4.8
     Share Exchange Agreement between Continental Ridge Resources Inc. (subsequently Nevada Geothermal Power Inc.) and Blue Mountain Power Company Inc., dated December 13, 2002.(1)4.9
     Geothermal Lease Agreement No. 189093 between Nevada Land and Resource Council and Power Company regarding Blue Mountain, effective date of March 31, 2003, as amended November 1, 2005.(1)4.10
     Geothermal Lease Agreement between Nevada Land Resource Company, LLC and Noramex Corporation, dated March 31, 2003.(1)4.11
     Consulting Agreement between Continental Ridge Resources and Goodman Capital, dated April 13, 2003.(1)4.12
     Assignment of Record Title Interest in a Lease for Oil and Gas or Geothermal Resources from United States Department of the Interior Bureau of Land Management to Ormat Nevada Inc., dated August 1, 2003.(1)4.13
     Memorandum of Geothermal Lease and Agreement No. 29-462-0003 between Newmont USA Limited, dba Newmont Mining Corporation and Nevada Geothermal Power, Inc. regarding Pumpernickel, dated February 13, 2004.(1)4.14
     Exercise of Option to Renew Lease No. 187556 between The Burlington Northern and Santa Fe Railway Company and Noramex Corporation regarding Blue Mountain, effective date of March 1, 2004.(1)4.15
     Offer to Lease and Lease for Geothermal Resources Lease No. 77668 between the Federal Bureau of Land Management and Noramex Corp. regarding Blue Mountain, effective date of August 1, 2004.(1)4.16
     Offer to Lease and Lease for Geothermal Resources Lease No. 80159 between, the Federal Bureau of Land Management and Noramex Corp. regarding Blue Mountain, effective date of August 1, 2004.(1)4.17
     Share Purchase Agreement between Nevada Geothermal Power Inc, Running Fox Resource Corp and Blue Desert Mining (US) Inc., dated August 27, 2004.(1)4.18
     Option Agreement between Nevada Geothermal Power Inc. and Sierra Geothermal Power Corp. (formerly Inovision Solutions Inc.) regarding
  112


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Pumpernickel, dated October 12, 2004.(1)4.19
     Amendment Agreement to Geothermal Option Agreement between Nevada Geothermal Power Inc. and Noramex Corp. and Inovision Solutions Inc., dated January 12, 2005.(1)4.20
     [Investor Relations Services] Agreement between Nevada Geothermal Power Inc. and The Equicom Group Inc., dated March 15, 2005.(1)4.21
     Lease Amendment No. 189099 between Nevada Land and Resource Council and Noramex Corporation regarding Black Warrior, dated May 1, 2005.(1)4.22
     Letter Agreement for Contract for Services between Nevada Geothermal Power Inc. and Domenic J. Falcone Associates, Inc., dated May 20, 2005, agreed and accepted on June 9, 2005.(1)4.23
     Amendment 1 to Letter Agreement for Contract for Services dated May 20, 2005 between Nevada Geothermal Power Inc. and Domenic J. Falcone Associates, Inc., dated May 20, 2005.(1)4.24
     Amendment 2 to Letter Agreement for Contract for Services dated May 20, 2005 between Nevada Geothermal Power Inc. and Domenic J. Falcone Associates, Inc., dated May 20, 2005.(1)4.25
     Stabb Geothermal Lease Agreement between Noramex Corporation and Stabb regarding Crump Geyser, effective date of August 1, 2005.(1)4.26
     Stabb Geothermal Lease Agreement between Noramex Corporation and LX Ranch Inc. regarding Crump Geyser, effective date of August 1, 2005.(1)4.27
     OKeefe Ranch Geothermal Lease Agreement between Noramex Corporation and O'Keefe Ranch regarding Crump Geyser, effective date of August 1, 2005.(1)4.28
     Consulting Agreement between Nevada Geothermal Power Inc. and Don J.A. Smith, dated October 1, 2005.(1)4.29
     Lease Amendment for Lease No. 189093 between Nevada Land and Resource Council, LLC and Noramex Corp. regarding Blue Mountain, dated November 1, 2005.(1)4.30
     Lease Amendment for Lease No. 189099 between Nevada Land and Resource Company, LLC and Noramex Corp. regarding Black Warrior, dated November 1, 2005.(1)4.31
     Decision of Federal Bureau of Land Management to consolidate
  113


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Geothermal Leases Nos. 77668 and 77669, dated November 3, 2005. (1)4.32
     Offer to Renew Lease Agreement between Nevada Geothermal Power Inc. and United Kingdom Building Limited for 409 Granville Street, Suite 900, Vancouver, BC, dated November 16, 2005.(1)4.33
     Lease Extension and Amending Agreement between Nevada Geothermal Power Inc. and United Kingdom Building Limited for 409 Granville Street, Suite 900, Vancouver, BC, dated November 29, 2005.(1)4.34
     Incentive Stock Option Plan adopted November 30, 2005 (Filed under Exhibit 2.2).(1)4.35
     Management Consulting Services Agreement between Nevada Geothermal Power Inc. and Tywell Management Inc., dated December 1, 2005.(1)4.36
     Services Agreement between Nevada Geothermal Power Inc. and Pro-Edge Consultants Inc., dated December 13, 2005.(1)4.37
     Technical Consulting Services Agreement between Nevada Geothermal Power Inc. and Fairbank Engineering Ltd., dated January 1, 2006.(1)4.38
     Geothermal Lease Agreement for The Crawford Farm area, Humboldt County, Nevada, between Power Company and The Crawford Farm regarding Blue Mountain, dated January 10, 2006.(1)4.39
     Standard Publicity Agreement between Jefferson Direct, Inc. and Nevada Geothermal Power Inc., dated February 2, 2006.(1)4.40
     Amendment Agreement to Geothermal Option Agreement between Nevada Geothermal Power Inc. and Sierra Geothermal Power Corp. (formerly Inovision Solutions Inc.) regarding Pumpernickel, dated February 14, 2006.(1)4.41
     BLM Winnemucca Field Office Geothermal Lease Stipulations No. NVN-78777, dated February 21, 2006.(1)4.42
     BLM Winnemucca Field Office Geothermal Lease Stipulations No. NVN-79745, dated February 21, 2006.(1)4.43
     Offer to Lease and Lease for Geothermal Resources Lease No. 79745 between the Federal Bureau of Land Management and Power Company regarding Black Warrior, effective date of March 1, 2006.(1)4.44
     Offer to Lease and Lease for Geothermal Resources Lease No. 78777 between the Federal Bureau of Land Management and Noramex Corp. regarding Black Warrior, effective date of March 1, 2006.(1)
  114


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4.45
     Geothermal Lease Agreement between Nevada Geothermal Power Company and Will DeLong regarding Blue Mountain, dated of April 15, 2006.(1)4.46
     Royalty Agreement between Nevada Geothermal Power Company, Ehni Enterprises Inc. and Ormat Nevada, Inc. regarding Pumpernickel, dated April 26, 2006.(1)4.47
     Agreement regarding the sale and purchase of BLM Lease No. 74855 between Ormat Nevada, Inc. and Nevada Geothermal Power Company regarding Pumpernickel, dated April 26, 2006.(1)4.48
     Unit Agreement for the Development and Operation of the Blue Mountain Unit Area, dated June 1, 2006.(1)4.49
     Offer to Lease and Lease for Geothermal Resources Lease No. 78124 between the Federal Bureau of Land Management and Noramex Corp. regarding Pumpernickel, effective date of June 1, 2006.(1)4.50
     Assignment of Record Title Interest in a Lease for Oil and Gas or Geothermal Resources for Lease No. 74855 from the Federal Bureau of Land Management to Nevada Geothermal Power Company regarding Pumpernickel, effective date of June 1, 2006.(1)4.51
     Daywork Drilling Contract between Nevada Geothermal Power Company and Calco Oil Field Industries, Inc. for Blue Mountain Geothermal, dated June 19, 2006.(1)4.52
     Internet Services & Consulting Contract between Nevada Geothermal Power Inc. and Inveslogic Inc., dated June 26, 2006.(1)4.53
     Offer to Lease and Lease for Geothermal Resources Lease No. 80070 between the Federal Bureau of Land Management and Noramex Corp. regarding Pumpernickel, effective date of August 1, 2006.(1)4.54
     Offer to Lease and Lease for Geothermal Resources Lease No. 80086 between the Federal Bureau of Land Management and Noramex Corp. regarding Blue Mountain, effective date of August 1, 2006.(1)4.55
     Offer to Lease and Lease for Geothermal Resources Lease No. 80159 between the Federal Bureau of Land Management and Noramex Corp. regarding Blue Mountain, effective date of August 1, 2006.(1)4.56
     Revised International Association of Drilling Contracts Drilling Bid Proposal and Daywork Drilling Contract  U.S. (Original Black Gold Contract) between Nevada Geothermal Power and Black Gold Equipment & Leasing LLC for Blue Mountain Geothermal Project, dated August 17,
  115


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2006.(1)4.57
     Long Term Firm Portfolio Energy Credit And Renewable Power Purchase Agreement between Nevada Geothermal Power Company, Inc. and NV Energy, dated August 18, 2006.(1)4.58
     Partial Assignment of Geothermal Lease No. 189093 between Nevada Land and Resource Council and Nevada Geothermal Power Company, Inc. regarding Blue Mountain, effective October 3, 2006.(1)4.59
     Notice of Lease Amendment for Lease No. 189093 between Nevada Land and Resource Council and Nevada Geothermal Power Company, Inc. regarding Blue Mountain, effective October 3, 2006.(1)4.60
     Offer to Renew Lease Agreement between Nevada Geothermal Power Inc. and United Kingdom Building Limited for 409 Granville Street, Suite 900, Vancouver, BC, dated January 10, 2007.(1)4.61
     Financial Consulting Agreement between Markus K. Christen and Nevada Geothermal Power Inc., dated January 12, 2007 and July 2nd,2007 financing engagement letter amendment. (1)4.62
     Amendment to Exhibits A and B of the Unit Agreement for the Development and Operation of the Blue Mountain Unit Area, dated January 24, 2007.(1)4.63
     Confidentiality Agreement between Morgan Stanley & Co Incorporated, Greenrock Capital, LLC and Nevada Geothermal Power Company, Inc., dated January 25, 2007.(1)4.64
     Form of Subscription Agreement for Units being purchased by residents of Alberta, British Columbia, Ontario, Quebec, Nova Scotia, Saskatchewan and offshore residents; closing February 22, 2007.(1)4.65
     Form of Subscription Agreement for Units being purchased by residents or citizens of the United States; closing February 22, 2007.(1)4.66
     Lease Agreement between Sheppard Rentals and Nevada Geothermal Power Company for 657 Anderson Street near Winnemucca in Humboldt County, Nevada, dated March 20, 2007.(1)4.67
     Development Loan Agreement between NGP Blue Mountain I LLC and Glitnir Banki hf dated November, 1, 2007. (2)4.68
     Promissory Note between NGP Blue Mountain I LLC and Glitnir Banki hf dated November 1, 2007.(2)4.69
     Pledge and Security Agreement by NGP Blue Mountain Holdco LLC and Glitnir Banki hf dated November 1, 2007.(2)
  116


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4.70
     Acknowledgement and Consent by NGP Blue Mountain I LLC with regard to Pledge and Security Agreement dated November 1, 2007.(2)4.71
     Assignment and Assumption of Power Purchase Agreement, by and between Nevada Geothermal Power Company and Borrower, dated October 24, 2007.(2)4.72
     Standard Large Generator Interconnect Agreement, by and between NV Energy and Borrower, dated November 5, 2007.(2)4.73
     Assignment and Assumption of Leases, by and among NGPI and NGPC, collectively as assignor, and Borrower, as assignee, dated as of October 24, 2007.(2)4.74
     State of Nevada Division of Water Resources Permit Nos. 72978, 73541,73542 AND 73543.(2)4.75
     Quitclaim Deed between Nevada Geothermal Power, Inc. and NGP Blue Mountain I LLC dated September 20, 2007.(2)4.76
     Amended and Restated Commitment Letter for US$100,000,000 Construction and Loan Facility For Project dated November 1, 2007.(2)4.77
     Commitment Letter for US$100,000,000 Equity Financing to be used to repay Construction Loan Financing dated July 24, 2007.(2)4.78
     Borrowers Officers & Secretarys Certificate, Exhibit B- Certificate of Formation dated November 1, 2007.(2)4.79
     NGPs Officers & Secretarys Certificate, Exhibit B- Certificate of Formation dated November 1, 2007.(2)4.80
     Contribution Agreement, by and among NGPI, NGPC, NGP and Borrower, dated as of September 19, 2007.(2)4.81
     First Amendment to Contribution Agreement, by and among NGPI, NGPC, NGP and Borrower, dated as of October 12, 2007 .(2)4.82
     Member Interest Certificate of NGP Blue mountain I LLC dated April 26, 2007.(2)4.83
     Indemnification Letter by Nevada Geothermal Power, Inc. dated November 1, 2007.(2)4.84
     Drilling Bid Proposal and Daywork Drilling Contract with ThermaSource Inc. dated December 1, 2007.(2)4.85
     Employment Agreement- Fairbank, dated October 1, 2007.(2)4.86
     Employment Letter Agreement- Studley, dated July 11, 2007.(2)4.87
     Employment Agreement-Walenciak, dated April 16, 2007.(2)4.88
     Second Amendment to Option Agreement for Pumpernickel Geothermal Property dated 12 December, 2007.(2)4.89
     Letter Agreement between Nevada Geothermal Power Inc. and Markus Christen dated January 12, 2007.(2)
  117


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4.90
     Professional Services Agreement between Integral Energy Management and Nevada Geothermal Power Company dated June 1, 2007.(2)4.91
     Chief Development Geologist Contract- Glenn Melosh dated November 6, 2007.(2)4.92
     Fairbank Engineering Ltd purchase and employment contract dated October 1 2007.(2)4.93
     Consulting agreement dated October 1, 2005, between Nevada Geothermal Power Inc and Frank Misseldine.(2)4.94
     Professional Services Agreement dated May 21, 2007, between R. Gordon Bloomquist and Nevada Geothermal Power Inc.(2)4.95
     Professional Services Agreement dated June 25, 2007, between Global Power Solutions and Nevada Geothermal Power Company.(2)4.96
     Engineering Services Agreement dated August 8, 2007, between GeothermEx Inc. and Nevada Geothermal Power Inc.(2)4.97
     Consulting Agreement dated November 28, 2007, between CCM Consulting a division of Cronus Capital Markets Inc. and Nevada Geothermal Power Co.(2)4.98
     Agreement between NGP Blue Mountain I, LLC and ThermaSource, Inc., dated November 29, 2007. (2)4.99
     Agreement between Nevada Geothermal Power, Inc. and Trinity Investments of Nevada, LLC, d/b/a Trinity Exploration (NSCB# - 00715910), for the drilling of Well 58A-15 at Blue Mountain, NV geothermal development site. Dated November 29, 2008. (3)4.100
     Agreement between Nevada Geothermal Power, Inc. and Trinity Investments of Nevada, LLC, d/b/a Trinity Exploration (NSCB# - 00715910) for the drilling of Well 57-15 at Blue Mountain, NV geothermal development site. Dated October 15, 2008. (3)4.101
     Agreement between Nevada Geothermal Power, Inc. and Ensign United States Drilling (California), Inc. for a geothermal multiple well program (guarantee 3 months work) at Blue Mountain, NV geothermal development site. Dated November 17, 2008. (3)4.102
     Note Purchase Agreement dated August 29, 2008 relating to the $US 180 million loan facility for the construction of the Blue Mountain Phase I 49.5 MW (gross) geothermal power plant with funds and accounts managed by TCW Asset Management Company (TCW). (3)
  118


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4.103
     First Amendment to Note Purchase Agreement relating to the US $180 million loan facility for the construction of the Blue Mountain Phase I 49.5 MW (gross) geothermal power plant with funds and accounts managed by TCW Asset Management Asset Management Company (TCW). Dated December 8, 2008.(3)4.104
     Second Amendment to Note Purchase Agreement to the $US 180 million loan facility for the construction of the Blue Mountain Phase I 49.5 MW (gross) geothermal power plant with funds and accounts managed by TCW Asset Management Asset Management Company (TCW). Dated December 12, 2008. (3)4.105
     First Amendment to MS Greenrock, LLC agreement (dated July 24, 2007) to adjust the amount of equity investment, removal of conditions related to project level construction loan, removal of right of first refusal and revisions to fixing of target return. Dated September 4, 2008.(3)(5)4.106
     Underwriting agreement with Dundee Securities Corporation, dated April 23, 2008. (3)(5)4.107
     Amendment to Agreement between Fairbank Engineering Ltd. (FEL) And Nevada Geothermal Power, Inc. (agreement dated October 1 2007). Dated January 8th, 2008. (3)4.108
     Agreement between NGP Blue Mountain HoldCO, LLC (Issuer) and TCW Asset Management Company for Issuer Pledge and Security Agreement pursuant to the terms of the Note Purchase Agreement dated August 29, 2008. (3)4.109
     Agreement between NGP Blue Mountain HoldCO, LLC (Issuer) and TCW Asset Management Company for an Account Management Agreement (Issuer), dated August 29, 2008. (3)4.110
     Guaranty between NGP Blue Mountain Holdco LLC (NGP I, Guarantor), and TCW Asset Management Company (Agent, Secured Party, Guarantied Party) for Note Holders of NGP I, pursuant to Note Purchase Agreement, dated August 29, 2008. (3)4.111
     Geothermal Lease Agreement for Hot Springs Ranch, at Nevada Geothermal Power, Inc.s Pumpernickel geothermal development site in Nevada. Lease between Allie Tipton Bear (owner of a one third interest) and Nevada Geothermal Power Company. Dated October 15, 2008. (3)4.112
     Memorandum of Geothermal Lease Agreement for Hot Springs Ranch at Nevada Geothermal Power Inc.s Pumpernickel geothermal development site in Nevada. Lease between Allie Tipton Bear (owner of a one third interest) and Nevada Geothermal Power Company. Dated October 15,
  119


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2008. (3)4.113
     Geothermal Lease Agreement for Hot Springs Ranch, at Nevada Geothermal Power Inc.s Pumpernickel geothermal development site in Nevada. Lease between Roger and Nancy Johnson (owner of a one third interest) and Nevada Geothermal Power Company. Dated October 15, 2008. (3)4.114
     Memorandum of Geothermal Lease Agreement for Hot Springs Ranch at Nevada Geothermal Power Inc.s Pumpernickel geothermal development site in Nevada. Lease between Robert and Nancy Johnson (owner of a one third interest) and Nevada Geothermal Power Company. Dated October 15, 2008. (3)4.115
     Surface and Access Rights to Township 33 North, Range 40 East, MDB & M, Section 5, and Section 4: South Half. Letter confirming additional rights to Geothermal Lease Agreement for Hot Springs Ranch at Nevada Geothermal Power Inc.s Pumpernickel geothermal development site in Nevada. (3)4.116
     Geothermal Lease Agreement for Hot Springs Ranch, at Nevada Geothermal Power Inc.s Pumpernickel geothermal development site in Nevada. Lease between Ruth Ann Danner f.k.a. Ruth Ann Tipton (owner of a one sixth interest) and Nevada Geothermal Power Company. Dated October 15, 2008. (3)4.117
     Lease Amendment to NLRC Contract NO. 189093 (March 31, 2003) between NLRC, the Lessor, and NGP Blue Mountain 1, LLC, as the Lessee. Dated March 31, 2009. (3)4.118
     Amendment to geothermal lease agreement (March 31, 2003) between Nevada Geothermal Power Company and RLF Nevada Properties, LLC for geothermal Lease #189093. Dated October 26, 2007. (3)4.119
     Memorandum of lease for all of Sections 15 and 23, Township 36 North, Range 34 East, MDB & M, at Blue Mountain, Nevada. (original lease October 19, 1993, and exercise option to renew on March 1, 2004) between BNSF Railway Company and Nevada Geothermal Power Company. Dated November 6, 2007. (3)4.120
     Letter dated November 13, 2008, to Bureau of Land Management referencing lease N-58196, N-77668, N080086 and N-80159. (3)4.121
     Letter dated November 13, 2008 to Bureau of Land Management referencing lease N-80070, N-7877, N-78124, N-79745 and N-74855. (3)4.122
     Cash Settled Option issued by NGP Blue Mountain HoldCO LLC. to Trust Company of the West for Note Holder (Boilermaker-Blacksmith
  120


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Pension Trust) of NGP 1, pursuant to Note Purchase Agreement. Dated: August 29, 2008. (3)4.123
     Form of Compensation Option Certificate with Dundee Securities Corporation in reference to Underwriting Agreement dated April 23, 2008. A copy of this document is referenced at exhibit 2.9 (3)4.124
     Form of Compensation Option Certificate with Clarus Securities, Inc. reference to Underwriting Agreement dated April 23, 2008. A copy of this document is referenced at exhibit 2.7(3)4.125
     Form of Compensation Option Certificate with Jacob & Company Securities in reference to Underwriting Agreement dated April 23, 2008. A copy of this document is referenced at exhibit 2.8 (3)4.129
     Engineering, Procurement and Construction Contract between NGP Blue Mountain, LLC and Ormat Nevada, Inc., dated March 28, 2008.(3)(5)4.130
     Engineering, Procurement and Construction Contract between NGP Blue Mountain, LLC and Wilson Utility Construction Company, dated September 12, 2008.(3)(5)4.131
     First Amendment to Long-Term Firm Portfolio Energy Credit and Renewable Power Purchase Agreement, dated November 3, 2008.(3)(5)4.132
     Cash Settled Option issued by NGP Blue Mountain HoldCO LLC. to Trust Company of the West for Note Holders (TEP Equity Holdings Cayman Blocker, Ltd.) of NGP 1, pursuant to Note Purchase Agreement. Dated: August 29, 2008. (3)4.133
     Cash Settled Option issued by NGP Blue Mountain HoldCO LLC. to Trust Company of the West for Note Holders (TCW Energy Fund XIV, L.P.) of NGP 1, pursuant to Note Purchase Agreement. Dated: August 29, 2008. (3)4.134
     Cash Settled Option issued by NGP Blue Mountain HoldCO LLC. to Trust Company of the West for Note Holders (TCW Energy Fund XIV-A, L.P.) of NGP 1, pursuant to Note Purchase Agreement. Dated: August 29, 2008. (3)4.135
     Cash Settled Option issued by NGP Blue Mountain HoldCO LLC. to Trust Company of the West for Note Holders (TCW Energy XIV Blocker (NGP Blue Mountain), L.L.C. of NGP 1, pursuant to Note Purchase Agreement. Dated: August 29, 2008. (3)4.136
     Memorandum of Geothermal Lease Agreement dated October 15, 2008 for Hot Springs Ranch at Nevada Geothermal Power Inc.s Pumpernickel
  121


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geothermal development site in Nevada. Lease between Ruth Ann Danner, f.k.a. Ruth Ann Tipton and Nevada Geothermal Power Company (owner of a one sixth interest), and Nevada Geothermal Power Company geothermal and solution mineral rights to 320 acres more or less (Section 4:South Half) of land in Humboldt County, Nevada. (3)4.137
     Geothermal Lease Agreement for Hot Springs Ranch, at Nevada Geothermal Power Inc.s Pumpernickel geothermal development site in Nevada. Lease between Rebecca Anne Hill f.k.a. Rebecca Ann Tipton (owner of a one sixth interest) and Nevada Geothermal Power Company. Dated October 15, 2008. (3)4.138
     Memorandum of Geothermal Lease Agreement dated October 15, 2008 for Hot Springs Ranch at Nevada Geothermal Power Inc.s Pumpernickel geothermal development site in Nevada. Lease between Rebecca Ann Hill f.k.a Rebecca Ann Tipton and Nevada Geothermal Power Company (owner of a one sixth interest), and Nevada Geothermal Power Company geothermal and solution mineral rights to 320 acres more or less (Section 4:South Half) of land in Humboldt County, Nevada. (3)4.139
     Second Amendment dated January 13, 2009, to Financial Consulting Agreement between Markus K. Christen and Nevada Geothermal Power Inc., dated January 12, 2007 and July 2nd, 2007 financing engagement letter. (4)4.140
     Amendment dated August 1, 2008 to Employment Letter Agreement  Studley, dated July 11, 2007(4)4.141
     Amendment dated April 16, 2008 to Employment Agreement  Walenciak. Dated April 16, 2007(4)4.142
     Purchase Agreement for Blue Claims, NMC 1001318-1001327, NMC1003767-1003783, NMC 1003784-1003787 from Gryphon Gold Corporation to Desert Valley Gold Company dated March 31, 2009(4)4.143
     Quitclaim Deed from Nevada Eagle Resources LLC (Grantor) to Desert Valley Gold (Grantee) and its successors and assigns forever, all rights, title and interest in the unpatented mining claims in Humboldt County, Nevada as referenced: NMC 1001318-1001327, NMC1003767-1003783, NMC 1003784-1003787, dated April 1, 2009(4)4.144
     Engineering and construction contract with Industrial Builders for the Geothermal Gathering System for the Faulkner Geothermal Power Generation Plant, Humboldt County, Nevada dated April 6, 2009. (4)(5)4.145
     Amendment as of April 10, 2009 between Nevada Land and Resource Company, LLC (NLRC) and Nevada Geothermal Power Company (Lessee) for Geothermal Lease #189093 dated March 31, 2003(4)
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4.146
     Note Purchase Agreement relating to the US$98.5 Million, 4.14% Senior Secured Notes with John Hancock Life Insurance Company as the Administrative Agent and the Department of Energy as the Guarantor, dated September 2, 2010.(6)4.147
     Letter Agreement for the Joint Development, Financing, Construction, Operation and Maintenance of Crump Geothermal Power Project by Ormat Nevada Inc. and Nevada Geothermal Power Inc., dated October 29, 2010. (6) (7)4.148
     Settlement Agreement, Waiver and Mutual Release, between NGP Blue Mountain I LLC and Ormat Nevada Inc., dated August 20, 2010. (6)4.149
     Amended and restated Note Purchase Agreement to the Note Purchase Agreement (dated August 29, 2008) between NGP Blue Mountain Holdco LLC and TCW Asset Management Company, dated September 2, 2010. (6)4.150
     Indenture of Trust and Security Agreement between NGP Blue Mountain I LLC and Wilmington Trust Company as Trustee, dated September 2, 2010.(6)4.151
     Assignment of geothermal lease dated June 10, 2010 between NGPC and NGP Crump 1 with regards to the OKeefe Ranch Geothermal Lease Agreement effective August 1, 2005. (6)4.152
     Assignment of geothermal lease dated June 10, 2010, between NGPC and NGP Crump 1 with regards to the LX Ranch Geothermal Lease Agreement effective August 1, 2005. (6)4.153
     Assignment of geothermal lease dated May 11, 2010, between NGPC and NGP Crump 1 with regards to the Stabb Ranch Geothermal Lease Agreement effective August 1, 2005. (6)4.154
     OKeeffe Ranch Geothermal Lease Agreement  Amending Agreement dated November 29, 2010. (6)4.155
     LX Ranch Geothermal Lease Agreement  Amending Agreement dated November 29, 2010. (6)4.156
     Stabb Geothermal Lease Agreement  Amending Agreement dated November 29, 2010. (6)4.157
     Assignment and Assumption Agreement of Geothermal Leases dated November 30, 2010 (6)4.158
     Limited Liability Company Agreement of Crump Geothermal Company LLC dated November 30, 2010. (6)
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4.159
     Assignment and Assumption Agreement dated November 30, 2010. (6)4.160
     Parent Company Guarantee dated November 30, 2010. (6)8.
     Subsidiaries8.1
     List of Subsidiaries (3)9.
     Statement re: Financial Statements9.1
     Annual Financials to June 30, 2010 (6)9.2
     Annual Financials to June 30, 2009 (6)9.3
     Independent Auditors Report 2008(6)11.
     Code of Ethics11.1 Code of Business Conduct and Ethics (incorporated as part of Item 15.1) (1)12.
     302 Certification12.1
     Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (6)12.2
     Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (6)13.
     906 Certification13.1
     Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (6)14.
     Legal OpinionNot Applicable
  (1)Incorporated by reference, to the same exhibit number, to the Companys Annual Report on Form 20-F, Amendment No. 1, for the year ended June 30, 2006, as filed with the Securities and Exchange Commission on September 25, 2007.(2)Incorporated by reference, to the same exhibit number, to the Companys Annual Report on Form 20-F, for the year ended June 30, 2007, as filed with the Securities and Exchange Commission on January 15, 2008. 124


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(3)Incorporated by reference, to the same exhibit number, to the Companys Annual Report on Form 20-F, for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on January 14, 2009.(4)Incorporated by reference, to the same exhibit number, to the Companys Annual Report on Form 20-F, for the year ended June 30, 2009, as filed with the Securities and Exchange Commission on November 26, 2009.(5)Material has been redacted from this exhibit and filed separately with the Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended.(6)Filed herewith.(7)Application has been made to the Securities and Exchange Commission to seek confidential treatment of certain portions of this Exhibit 4.144 under Rule 24b-2 of the Securities Exchange Act of 1934, as amended. Omitted material for which confidential treatment has been requested has been filed separately with the Securities and Exchange Commission. SIGNATURES The Registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf. NEVADA GEOTHERMAL POWER INC. By: /s/ Brian Fairbank Brian D. Fairbank
President, Chief Executive Officer and Director Dated: December 17, 2010 125


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